DCP Midstream (DCP-PC) 10-K 15 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 03, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	DPM
Entity Registrant Name	DCP MIDSTREAM, LP
Entity Central Index Key	1,338,065
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		143,302,328
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,121,014,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 1	$ 2
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1 million	62	73
Affiliates	94	81
Inventories	44	43
Unrealized gains on derivative instruments	16	105
Other	10	2
Total current assets	227	306
Property, plant and equipment, net	3,272	3,476
Goodwill	72	72
Intangible assets, net	103	112
Investments in unconsolidated affiliates	1,475	1,493
Unrealized gains on derivative instruments	0	9
Other long-term assets	12	9
Total assets	5,161	5,477
Accounts payable:
Trade	108	98
Affiliates	31	19
Long-term Debt, Current Maturities	500	0
Unrealized losses on derivative instruments	29	18
Interest Payable, Current	18	19
Taxes Payable, Current	19	12
Disposal Group, Including Discontinued Operation, Liabilities, Current	500
Other	29	34
Total current liabilities	734	200
Long-term debt	1,750	2,424
Unrealized losses on derivative instruments	0	1
Other long-term liabilities	44	47
Total liabilities	2,528	2,672
Commitments and contingent liabilities
Equity:
Limited partners (114,749,848 and 114,742,948 common units issued and outstanding, respectively)	2,591	2,762
General partner	18	18
Accumulated other comprehensive loss	(8)	(8)
Total partners' equity	2,601	2,772
Noncontrolling interests	32	33
Total equity	2,633	2,805
Total liabilities and equity	$ 5,161	$ 5,477

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 0	$ 1
Common unitholders, units issued	114,749,848	114,740,148
Common unitholders, units outstanding	114,749,848	114,740,148

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$ 1,093	$ 1,442	$ 3,143
Transportation, processing and other	424	371	345
Gain (Loss) on Derivative Instruments, Net, Pretax	(20)	85	154
Total operating revenues	1,497	1,898	3,642
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	946	1,246	2,795
Operating and maintenance expense	183	214	216
Depreciation and amortization expense	122	120	110
General and administrative expense	88	85	64
Goodwill, Impairment Loss	0	82	0
Other Operating Income (Expense), Net	7	4	3
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	(47)	0	0
Total operating costs and expenses	1,299	1,751	3,188
Operating Income (Loss)	198	147	454
Interest Expense	(94)	(92)	(86)
Earnings from unconsolidated affiliates	214	173	75
Income before income taxes	318	228	443
Income tax expense	0	5	(6)
Net income	318	233	437
Net income attributable to noncontrolling interests	(6)	(5)	(14)
Net income attributable to partners	312	228	423
Net income attributable to predecessor operations	0	0	(6)
General partner's interest in net income	(124)	(124)	(114)
Net income allocable to limited partners	$ 188	$ 104	$ 303
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 1.64	$ 0.91	$ 2.84
Weighted Average Limited Partnership Units Outstanding, Basic	114,700	114,600	106,600
Weighted Average Limited Partnership Units Outstanding, Diluted	114,700	114,600
Third Party [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	$ 348	$ 484	$ 963
Transportation, processing and other	257	253	239
Gain (Loss) on Derivative Instruments, Net, Pretax	(7)	52	36
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	814	1,139	2,524
General and administrative expense	14	11	17
Affiliated Entity [Member]
Operating revenues:
Sales of natural gas, propane, NGLs and condensate	745	958	2,180
Transportation, processing and other	167	118	106
Gain (Loss) on Derivative Instruments, Net, Pretax	(13)	33	118
Operating costs and expenses:
Purchases of natural gas, propane and NGLs	132	107	271
General and administrative expense	$ 74	$ 74	$ 47

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 80	$ 120	$ 46	$ 72	$ 94	$ 72	$ (2)	$ 69	$ 318	$ 233	$ 437
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings									0	1	2
Total other comprehensive income									0	1	2
Total comprehensive income									318	234	439
Total comprehensive income attributable to noncontrolling interests									(6)	(5)	(14)
Total comprehensive income attributable to partners									$ 312	$ 229	$ 425

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net income	$ 318	$ 233	$ 437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	122	120	110
Earnings from unconsolidated affiliates	(214)	(173)	(75)
Distributions from unconsolidated affiliates	258	201	120
Net unrealized losses (gains) on derivative instruments	108	131	(86)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	(47)	0	0
Goodwill, Impairment Loss	0	82	0
Other, net	12	13	14
Change in operating assets and liabilities, which provided (used) cash, net of effects of acquisitions:
Accounts receivable	(3)	110	68
Inventories	(1)	20	4
Accounts payable	25	(90)	(67)
Accrued interest	0	(2)	8
Other current assets and liabilities	(3)	0	(5)
Other long-term assets and liabilities	0	5	(4)
Net cash provided by operating activities	575	650	524
INVESTING ACTIVITIES:
Capital expenditures	(37)	(281)	(338)
Acquisitions, net of cash acquired	0	0	(102)
Payments to Acquire Equity Method Investments	0	0	673
Acquisition of unconsolidated affiliates			(673)
Investments in unconsolidated affiliates, net	(29)	(62)	(151)
Proceeds from sale of assets	160	0	28
Net cash provided by (used in) investing activities	94	(343)	(1,236)
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,972	1,554	719
Payments of long-term debt	(2,152)	(1,429)	0
Payments of commercial paper, net	0	0	(335)
Payments of deferred financing costs	0	0	(7)
Excess purchase price over acquired interests	0	0	(18)
Proceeds from issuance of common units, net of offering costs	0	31	1,001
Net change in advances to predecessor from DCP Midstream, LLC	0	0	(6)
Distributions to limited partners and general partner	(483)	(482)	(420)
Distributions to noncontrolling interests	(7)	(5)	(14)
Purchase of additional interest in a subsidiary	0	0	(198)
Contributions from noncontrolling interests	0	0	3
Payments Of Distributions To Parent			(198)
Contributions from DCP Midstream, LLC	0	1	0
Net cash (used in) provided by financing activities	(670)	(330)	725
Net change in cash and cash equivalents	(1)	(23)	13
Cash and cash equivalents, beginning of period	2	25	12
Cash and cash equivalents, end of period	$ 1	$ 2	$ 25

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Mont Belvieu Fractionators [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Noncontrolling Interests [Member]	General Partner [Member]	Limited Partner [Member]	Limited Partner [Member]Mont Belvieu Fractionators [Member]
Beginning balance (Predecessor Equity [Member]) at Dec. 31, 2013	$ 40
Beginning balance at Dec. 31, 2013	2,213		$ (11)	$ 228	$ 8	$ 1,948
Net income | Predecessor Equity [Member]	6
Net income	437			14	114	303
Other comprehensive (loss) income | Predecessor Equity [Member]	0
Other comprehensive (loss) income	2		2
Partners Capital Net Change In Parent Advances To Predecessor | Predecessor Equity [Member]	(6)
Partners Capital Net Change In Parent Advances To Predecessor	(6)
Partners' Capital Account, Acquisitions | Predecessor Equity [Member]	(40)
Partners' Capital Account, Acquisitions	(40)		0	0	0	0
Partners Capital Account Acquisitions Issuance Of Units	225					225
Excess purchase price over carrying value of acquired net assets	(178)					(178)
Issuance of common units | Predecessor Equity [Member]	0
Issuance of common units	1,002		0	0	0	1,002
Distributions to limited partners and general partner | Predecessor Equity [Member]	0
Distributions to limited partners and general partner	(420)		0	0	(104)	(316)
Distributions to noncontrolling interests | Predecessor Equity [Member]	0
Distributions to noncontrolling interests	(14)		0	(14)	0	0
Contributions from noncontrolling interests | Predecessor Equity [Member]	0
Contributions from noncontrolling interests	3		0	3	0	0
Acquisition of additional interest in subsidiary | Predecessor Equity [Member]	0
Acquisition of additional interest in subsidiary	(198)		0	(198)	0	0
Ending balance (Predecessor Equity [Member]) at Dec. 31, 2014	0
Ending balance at Dec. 31, 2014	3,026		(9)	33	18	2,984
Net income	233			5	124	104
Other comprehensive (loss) income	1		1
Excess purchase price over carrying value of acquired net assets		$ 1					$ 1
Issuance of common units	31		0	0	0	31
Distributions to limited partners and general partner	(482)		0	0	(124)	(358)
Distributions to noncontrolling interests	(5)		0	(5)	0	0
Contributions from noncontrolling interests	0
Ending balance at Dec. 31, 2015	2,805		(8)	33	18	2,762
Net income	318			6	124	188
Other comprehensive (loss) income	0
Distributions to limited partners and general partner	(483)				(124)	(359)
Distributions to noncontrolling interests	(7)			(7)
Contributions from noncontrolling interests	0
Ending balance at Dec. 31, 2016	$ 2,633		$ (8)	$ 32	$ 18	$ 2,591

Consolidated Statements of Cha8

Consolidated Statements of Changes in Equity (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Issuance of common units		790,280
Limited Partner [Member]
Consideration financed through issuance of common units			4,497,158
Issuance of common units	0

Description of Business and Bas

Description of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation DCP Midstream, LP, with its consolidated subsidiaries, or us, we, our or the Partnership, is engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate; and transporting, storing and selling propane in wholesale markets. We are a Delaware limited partnership that was formed in August 2005. Our Partnership includes our Natural Gas Services, NGL Logistics and Wholesale Propane Logistics segments. For additional information regarding these segments, see Note 19 - Business Segments. Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. During the third quarter of 2016, Spectra Energy entered into an Agreement and Plan of Merger (the "Merger Agreement") with Enbridge Inc. ("Enbridge"), a Canadian corporation, and anticipates completing the proposed merger during the first quarter of 2017. The Merger Agreement provides that, upon closing of the proposed merger, Spectra Energy will continue its separate corporate existence as a wholly owned subsidiary of Enbridge. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. DCP Midstream, LLC’s employees provide administrative support to us and operate most of our assets. As of December 31, 2016 DCP Midstream, LLC owned approximately 21.4% of us, including limited partner and general partner interests. On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. For additional information regarding the Transaction, see Note 4 - Acquisitions. The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other DCP Midstream, LLC operations have been included in the consolidated financial statements as transactions between affiliates.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Income Tax, Policy [Policy Text Block]	Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal income tax returns of each partner.
Significant Accounting Policies [Text Block]	Summary of Significant Accounting Policies Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents. Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections. Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory. Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchase or normal sale exception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows: Classification of Contract Accounting Method Presentation of Gains & Losses or Revenue & Expense Cash Flow Hedge Hedge method (a) Gross basis in the same consolidated statements of operations category as the related hedged item Fair Value Hedge Hedge method (a) Gross basis in the same consolidated statements of operations category as the related hedged item Normal Purchases or Normal Sales Accrual method (b) Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale Other Non-Trading Derivative Activity Mark-to-market method (c) Net basis in gains and losses from commodity derivative activity ______________ (a) Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item. (b) Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings. (c) Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period. Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings. The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations. Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps. Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled. Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill at the reporting unit level during the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows. Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized. Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to: • significant adverse change in legal factors or business climate; • a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; • significant adverse changes in the extent or manner in which an asset is used, or in its physical condition; • a significant adverse change in the market value of an asset; or • a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows. Unamortized Debt Discount and Expense - Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The discounts and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt. Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third party and affiliate investors. Revenue Recognition - We generate the majority of our revenues from gathering, compressing, treating, processing, transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by receiving fees. We also generate revenue from transporting, storing and selling propane. We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements: • Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. • Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate. • Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their customers. Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments. We recognize revenues for sales and services under the four revenue recognition criteria, as follows: • Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract. • Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser. • The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody. • Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected. We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. We recognize revenues for non-trading commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity derivative activity . These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial and physical energy trading contracts. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Purchases of natural gas, propane and NGLs - Purchases of natural gas and NGLs represent physical purchases from suppliers. We purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2016 , 2015 and 2014 . However, we had significant transactions with affiliates. Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. There were no environmental liabilities included in the consolidated balance sheet as other current liabilities at December 31, 2016 and 2015, and other long-term liabilities were $1 million at both December 31, 2016 and 2015 . Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal income tax returns of each partner. Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

New Accounting Pronouncements (

New Accounting Pronouncements (Notes)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated statement of cash flows. FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures. FASB ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, with the option to early adopt for financial statements that have not been issued. The impact of this ASU will be evaluated upon the occurrence of future business combinations and provisional adjustments will be recorded in the period determined. FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU was effective for annual reporting periods beginning after December 15, 2015. The retrospective adoption of this ASU has been implemented and did not have any impact on our consolidated results of operations, cash flows and financial position. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions	Acquisitions On January 1, 2017 , DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. This represents a Transaction between entities under common control and a change in reporting entity. There was no financial statement impact for the year ended December 31, 2016. Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, the General Partner, in its capacity as the general partner of the Partnership, entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.

Assets Held for Sale (Notes)

Assets Held for Sale (Notes)	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	In May 2016, we entered into a purchase and sale agreement with a third party to sell our 100% interest in our Northern Louisiana system, which primarily consisted of certain gas processing plants and gathering systems, within our Natural Gas Services segment, for approximately $160 million , subject to customary purchase price adjustments. This transaction closed on July 1, 2016 and we recorded a gain of $47 million in the third quarter of 2016.

Agreements and Transactions wit

Agreements and Transactions with Affiliates	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Agreements and Transactions with Affiliates	Agreements and Transactions with Affiliates DCP Midstream, LLC Services Agreement and Other General and Administrative Charges Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended (the “Original Services Agreement”). Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for salaries of personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. Under the Original Services Agreement, we were required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also paid DCP Midstream, LLC an annual fee under the Original Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual fee, there was no limit on the reimbursements we make to DCP Midstream, LLC under the Original Services Agreement for other expenses and expenditures incurred or payments made on our behalf. The annual fee paid under the Original Services Agreement was $71 million for the year ended December 31, 2016. The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC: Year Ended December 31, 2016 2015 2014 (Millions) Services Agreement $ 71 $ 71 $ 41 Other fees — DCP Midstream, LLC 3 3 6 Total — DCP Midstream, LLC $ 74 $ 74 $ 47 In addition to the fees paid pursuant to the Services Agreement, we incurred allocated expenses, including executive compensation, insurance and internal audit fees with DCP Midstream, LLC of $3 million , $3 million and $2 million for each of the years ended December 31, 2016 , 2015 and 2014 respectively. The Eagle Ford system incurred $4 million in general and administrative expenses directly from DCP Midstream, LLC for the year ended December 31, 2014, before the reallocation of the Eagle Ford system to the Original Services Agreement on March 31, 2014. Commodity Transactions - We sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering, transportation and other services to, DCP Midstream, LLC. Spectra Energy Commodity Transactions - We purchase natural gas and other NGL products from Spectra Energy. Management anticipates continuing to purchase commodities and provide services to Spectra Energy in the ordinary course of business. Summary of Transactions with Affiliates The following table summarizes our transactions with affiliates: Year Ended December 31, 2016 2015 2014 (Millions) DCP Midstream, LLC: Sales of natural gas, propane, NGLs and condensate $ 745 $ 958 $ 2,179 Transportation, processing and other $ 167 $ 118 $ 92 Purchases of natural gas, propane and NGLs $ 100 $ 61 $ 194 (Losses) gains from commodity derivative activity, net $ (13 ) $ 33 $ 118 Operating and maintenance expense $ — $ — $ 1 General and administrative expense $ 74 $ 74 $ 47 Phillips 66: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1 Spectra Energy: Purchases of natural gas, propane and NGLs $ 32 $ 46 $ 77 Transportation, processing and other $ — $ — $ 14 Other income $ — $ 5 $ — We had balances with affiliates as follows: December 31, December 31, (Millions) DCP Midstream, LLC: Accounts receivable $ 94 $ 81 Accounts payable $ 28 $ 15 Unrealized gains on derivative instruments — current $ 15 $ 32 Unrealized gains on derivative instruments — long-term $ — $ 9 Unrealized losses on derivative instruments — current $ 22 $ 18 Unrealized losses on derivative instruments — long-term $ — $ 1 Spectra Energy: Accounts payable $ 3 $ 4

Inventories

Inventories	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventories	Inventories Inventories were as follows: December 31, December 31, (Millions) Natural gas $ 28 $ 29 NGLs 16 14 Total inventories $ 44 $ 43 We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the consolidated statements of operations. We recognized $3 million , $8 million and $24 million in lower of cost or market adjustments during the years ended December 31, 2016 , 2015 , and 2014, respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment A summary of property, plant and equipment by classification is as follows: Depreciable Life December 31, December 31, (Millions) Gathering and transmission systems 20 — 50 Years $ 2,046 $ 2,337 Processing, storage, and terminal facilities 35 — 60 Years 2,342 2,327 Other 3 — 30 Years 63 64 Construction work in progress 89 122 Property, plant and equipment 4,540 4,850 Accumulated depreciation (1,268 ) (1,374 ) Property, plant and equipment, net $ 3,272 $ 3,476 Interest capitalized on construction projects was less than $1 million , $6 million and $8 million for the years ended December 31, 2016 , 2015 and 2014, respectively. Depreciation expense was $112 million , $110 million and $101 million for the years ended December 31, 2016 , 2015 and 2014, respectively. Asset Retirement Obligations - As of December 31, 2016 and 2015 , we had asset retirement obligations of $28 million and $29 million , respectively, included in other long-term liabilities in the consolidated balance sheets. Accretion expense was $2 million for the each of the years ended December 31, 2016 , 2015 , and 2014. We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

Goodwill and Intangible assets

Goodwill and Intangible assets Goodwill and Intangible assets	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets Disclosure [Text Block]	Goodwill and Intangible Assets We performed our annual goodwill assessment during the quarter ended September 30, 2016 at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the fair value of goodwill substantially exceeded its carrying value and that the entire amount of goodwill disclosed on the consolidated balance sheet as of September 30, 2016 is recoverable. We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information (including forecasted volumes and commodity prices), as well as historical and other factors. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. During the second quarter of 2015, we recognized a goodwill impairment based on our best estimate of the impairment resulting from the performance of the hypothetical purchase price allocation which totaled $49 million from our Collbran, Michigan, and Southeast Texas reporting units. We completed the hypothetical purchase price allocation in the third quarter of 2015 and after completing the analysis, there was no remaining fair value to assign to the goodwill of the Collbran reporting unit. As a result, we recorded an additional impairment of $33 million in the third quarter of 2015. We performed our annual goodwill assessment during the quarter ended September 30, 2015. We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the condensed consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of our annual goodwill assessment. The change in carrying amount of goodwill in each of our reporting segments was as follows: Year Ended December 31, 2016 2015 Natural Gas Services NGL Logistics Wholesale Propane Logistics Total Natural Gas Services NGL Logistics Wholesale Propane Logistics Total Balance, beginning of period $ — $ 35 $ 37 $ 72 $ 82 $ 35 $ 37 $ 154 Impairment — — — — (82 ) — — (82 ) Balance, end of period $ — $ 35 $ 37 $ 72 $ — $ 35 $ 37 $ 72 Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows: December 31, 2016 2015 (Millions) Gross carrying amount $ 164 $ 164 Accumulated amortization (61 ) (52 ) Intangible assets, net $ 103 $ 112 We recorded amortization expense of $9 million , $8 million and $9 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. As of December 31, 2016 , the remaining amortization periods ranged from approximately 5 years to 19 years, with a weighted-average remaining period of approximately 14 years. Estimated future amortization for these intangible assets is as follows: Estimated Future Amortization (Millions) 2017 $ 8 2018 8 2019 8 2020 8 2021 8 Thereafter 63 Total $ 103

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates The following table summarizes our investments in unconsolidated affiliates: Carrying Value as of Percentage Ownership December 31, December 31, (Millions) DCP Sand Hills Pipeline, LLC 33.33% $ 454 $ 441 Discovery Producer Services LLC 40% 386 406 DCP Southern Hills Pipeline, LLC 33.33% 315 318 Front Range Pipeline LLC 33.33% 165 170 Texas Express Pipeline LLC 10% 93 96 Mont Belvieu Enterprise Fractionator 12.5% 23 25 Panola Pipeline Company, LLC 15% 25 19 Mont Belvieu 1 Fractionator 20% 10 11 Other Various 4 7 Total investments in unconsolidated affiliates $ 1,475 $ 1,493 Earnings from investments in unconsolidated affiliates were as follows: Year Ended December 31, 2016 2015 2014 (Millions) Discovery Producer Services LLC $ 74 $ 55 5 DCP Sand Hills Pipeline, LLC 61 55 24 DCP Southern Hills Pipeline, LLC 24 14 13 Front Range Pipeline LLC 19 17 2 Mont Belvieu Enterprise Fractionator 16 15 16 Mont Belvieu 1 Fractionator 10 9 12 Texas Express Pipeline LLC 8 8 3 Panola Pipeline Company, LLC 2 — — Total earnings from unconsolidated affiliates $ 214 $ 173 $ 75 The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Year Ended December 31, 2016 2015 2014 (Millions) Statements of operations (a): Operating revenue $ 1,321 $ 1,172 $ 826 Operating expenses $ 552 $ 540 $ 475 Net income $ 765 $ 630 $ 349 December 31, December 31, (Millions) Balance sheets (a): Current assets $ 196 $ 182 Long-term assets 5,272 5,200 Current liabilities (166 ) (170 ) Long-term liabilities (202 ) (216 ) Net assets $ 5,100 $ 4,996 (a) In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016. As a result, activity related to Panola is included in the tables above as of and for the year ended December 31, 2016.

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement Determination of Fair Value Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market. • Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided. • Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date. • Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant. We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 13 - Risk Management and Hedging Activities. Valuation Hierarchy Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows. • Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets. • Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3 — inputs are unobservable and considered significant to the fair value measurement. A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy. Commodity Derivative Assets and Liabilities We enter into a variety of derivative financial instruments, which may include over-the-counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts. Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified within Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3. Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs. Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data. Interest Rate Derivative Assets and Liabilities We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation. Nonfinancial Assets and Liabilities We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3. For the year ended December 31, 2015, we recognized goodwill impairment of $82 million in our consolidated statements of operations. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. The following table presents the financial instruments carried at fair value as of December 31, 2016 and 2015 , by consolidated balance sheet caption and by valuation hierarchy, as described above: December 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (Millions) Current assets: Commodity derivatives (a) $ 1 $ 15 $ — $ 16 $ — $ 83 $ 22 $ 105 Short-term investments (b) $ — $ — $ — $ — $ 2 $ — $ — $ 2 Long-term assets: Commodity derivatives (c) $ — $ — $ — $ — $ — $ 9 $ — $ 9 Current liabilities: Commodity derivatives (d) $ (1 ) $ (23 ) $ (5 ) $ (29 ) $ — $ (18 ) $ — $ (18 ) Long-term liabilities: Commodity derivatives (e) $ — $ — $ — $ — $ — $ (1 ) $ — $ (1 ) (a) Included in current unrealized gains on derivative instruments in our consolidated balance sheets. (b) Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets. (c) Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets. (d) Included in current unrealized losses on derivative instruments in our consolidated balance sheets. (e) Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets. Changes in Levels 1 and 2 Fair Value Measurements The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the years ended December 31, 2016 and 2015 , there were no transfers into or out of Level 1 and Level 2 of the fair value hierarchy. Changes in Level 3 Fair Value Measurements The tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions. We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities. Commodity Derivative Instruments Current Assets Long- Term Assets Current Liabilities Long- Term Liabilities (Millions) Year ended December 31, 2016 (a): Beginning balance $ 22 $ — $ — $ — Net unrealized losses included in earnings (b) — — (5 ) — Settlements (22 ) — — — Ending balance $ — $ — $ (5 ) $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ — $ — $ (5 ) $ — Year ended December 31, 2015 (a): Beginning balance $ 138 $ 18 $ — $ — Net unrealized gains (losses) included in earnings (b) 29 (18 ) — — Settlements (145 ) — — — Ending balance $ 22 $ — $ — $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 21 $ (18 ) $ — $ — (a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015 . (b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net. Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. December 31, 2016 Product Group Fair Value Forward Curve Range (Millions) Liabilities NGLs $ (5 ) $0.66-$1.23 Per gallon Estimated Fair Value of Financial Instruments Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point. We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value. We determine the fair value of our fixed-rate Senior Notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our Amended and Restated Credit Agreement based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of December 31, 2016 and 2015 , the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, and our Amended and Restated Credit Agreement were as follows: December 31, 2016 December 31, 2015 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (Millions) Senior Notes $ 2,066 $ 2,022 $ 2,063 $ 1,650 Amended and Restated Credit Agreement $ 195 $ 195 $ 375 $ 375 (a) Excludes unamortized issuance costs.

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Debt December 31, December 31, (Millions) Amended and Restated Credit Agreement Revolving credit facility, weighted-average variable interest rate of 2.01% and 1.57%, as of December 31, 2016 and 2015 , respe ctively, due May 1, 2019 $ 195 $ 375 Debt Securities Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017 500 500 Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019 325 325 Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022 350 350 Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023 500 500 Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044 400 400 Unamortized issuance costs (11 ) (14 ) Unamortized discount (9 ) (12 ) Total debt 2,250 2,424 Current maturities of long-term debt 500 — Total long-term debt $ 1,750 $ 2,424 Amended and Restated Credit Agreement We have a $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019 , or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions. Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate, plus 0.50% or the LIBOR Market Index rate, plus 1% , plus (b) an applicable margin of 0.45% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement. As of December 31, 2016 , we had unused borrowing capacity of $1,031 million , net of $24 million of letters of credit, under the Amended and Restated Credit Agreement, of which $970 million was available for working capital and other general partnership purposes. Our borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date. The Amended and Restated Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended and Restated Credit Agreement) of not more than 5.0 to 1.0 , and following the consummation of qualifying acquisitions, not more than 5.5 to 1.0 , on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated. Debt Securities The notes are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness, including indebtedness under our Amended and Restated Credit Agreement. We are not required to make mandatory redemption or sinking fund payments with respect to any of these notes, and they are redeemable at a premium at our option. The future maturities of debt in the year indicated are as follows: Debt Maturities (Millions) 2017 $ 500 2018 — 2019 520 2020 — 2021 — Thereafter 1,250 2,270 Unamortized issuance costs (11 ) Unamortized discount (9 ) Total $ 2,250

Risk Management and Hedging Act

Risk Management and Hedging Activities	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management and Hedging Activities	Risk Management and Hedging Activities Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage. Commodity Price Risk Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through the first quarter of 2018 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. The type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity. Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of operations as a gain or loss on commodity derivative activity. Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016 . Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates. The balance in AOCI of our previously settled interest rate swap cash flow hedges was in a loss position of $3 million as of December 31, 2016 . Contingent Credit Features Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances. We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below. • If we were to have an effective event of default under our Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions. • Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade. • Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Amended and Restated Credit Agreement. As of December 31, 2016 , we were not a party to any agreements that would trigger the cross-default provisions. Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2016 , all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2016 , we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. Collateral As of December 31, 2016, we had cash deposits of $9 million , included in other current assets in our consolidated balance sheets. Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller. Offsetting Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments: December 31, 2016 December 31, 2015 Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments (a) Net Amount Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments (a) Net Amount (Millions) Assets: Commodity derivatives $ 16 $ (15 ) $ 1 $ 114 $ (19 ) $ 95 Liabilities: Commodity derivatives $ (29 ) $ 15 $ (14 ) $ (19 ) $ 19 $ — (a) There is no cash collateral pledged or received against these positions. Summarized Derivative Information The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of December 31, 2016 and 2015 . Balance Sheet Line Item December 31, December 31, Balance Sheet Line Item December 31, December 31, (Millions) (Millions) Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging Instruments: Commodity derivatives: Commodity derivatives: Unrealized gains on derivative instruments — current $ 16 $ 105 Unrealized losses on derivative instruments — current $ (29 ) $ (18 ) Unrealized gains on derivative instruments — long-term — 9 Unrealized losses on derivative instruments — long-term — (1 ) Total $ 16 $ 114 Total $ (29 ) $ (19 ) The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2016 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. For the year ended December 31, 2016 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our consolidated statements of operations. For the year ended December 31, 2016 , no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (4 ) $ (6 ) $ 1 $ (9 ) Losses reclassified from AOCI to earnings — effective portion 1 (b) — — 1 Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. (b) Included in interest expense in our consolidated statements of operations. For the year ended December 31, 2015 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our consolidated statements of operations. For the year ended December 31, 2015 , no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected: Commodity Derivatives: Statements of Operations Line Item Year Ended December 31, 2016 2015 2014 (Millions) Third party: Realized gains (losses) $ 72 $ 158 $ (2 ) Unrealized (losses) gains (79 ) (106 ) 38 (Losses) gains from commodity derivative activity, net $ (7 ) $ 52 $ 36 Affiliates: Realized gains $ 16 $ 57 $ 70 Unrealized (losses) gains (29 ) (24 ) 48 (Losses) gains from commodity derivative activity, net —affiliates $ (13 ) $ 33 $ 118 We do not have any derivative financial instruments that qualify as a hedge of a net investment. The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below. December 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net Short Position (Bbls) Net Long Position (MMBtu) 2017 (212,000 ) (21,192,500 ) (1,605,000 ) 1,567,500 2018 (28,000 ) — — — December 31, 2015 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net Short Position (Bbls) Net Long Position (MMBtu) 2016 (1,408,672 ) (15,881,064 ) (813,267 ) 2,665,000 2017 — (7,387,500 ) — 1,800,000

Partnership Equity and Distribu

Partnership Equity and Distributions	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Partnership Equity and Distributions	Partnership Equity and Distributions During the year ended December 31, 2016 , we issued no common units pursuant to our 2014 equity distribution agreement. As of December 31, 2016 , approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement. During the year ended December 31, 2015 , we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $31 million , net of commissions and offering costs of less than $1 million . In June 2014, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $500 million , which became effective on July 11, 2014. The shelf registration statement allows us to issue additional common units. In September 2014, we entered into an equity distribution agreement, or the 2014 equity distribution agreement, with a group of financial institutions as sales agents. The 2014 equity distribution agreement provides for the offer and sale from time to time, through our sales agents, of common units having an aggregate offering amount of up to $500 million . During the year ended December 31, 2014, we issued 2,256,066 of our common units pursuant to the 2014 equity distribution agreement and received proceeds of $119 million , net of commissions and accrued offering costs of $1 million , which were used to finance growth opportunities and for general partnership purposes. In March 2014, we issued 14,375,000 common units to the public at $48.90 per unit. We received proceeds of $677 million , net of offering costs. In March 2014, we issued 4,497,158 common units to DCP Midstream, LLC as partial consideration for certain transactions that closed in March 2014. Definition of Available Cash — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined in the partnership agreement, to unitholders of record on the applicable record date, as determined by our general partner. Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter: • less the amount of cash reserves established by the general partner to: • provide for the proper conduct of our business; • comply with applicable law, any of our debt instruments or other agreements; and • provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters; • plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter. General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 0.3% and limited partner interest of approximately 1.7% as of December 31, 2016. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights. Distributions of Available Cash - Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter in the following manner: • first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter; • second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter; • third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and • thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders. The following table presents our cash distributions paid in 2016 , 2015 and 2014: Payment Date Per Unit Distribution Total Cash Distribution (Millions) November 14, 2016 $ 0.7800 $ 120 August 12, 2016 $ 0.7800 $ 121 May 13, 2016 $ 0.7800 $ 121 February 12, 2016 $ 0.7800 $ 121 November 13, 2015 $ 0.7800 $ 120 August 14, 2015 $ 0.7800 $ 121 May 15, 2015 $ 0.7800 $ 121 February 13, 2015 $ 0.7800 $ 120 November 14, 2014 $ 0.7700 $ 117 August 14, 2014 $ 0.7575 $ 111 May 15, 2014 $ 0.7450 $ 106 February 14, 2014 $ 0.7325 $ 86

Equity-Based Compensation (Note

Equity-Based Compensation (Notes) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Allocated Share-based Compensation Expense	$ 1	$ 1	$ 1
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	Equity-Based Compensation On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 Long-Term Incentive Plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and, together with the 2012 LTIP and the 2016 LTIP, the “LTIP”). Any outstanding awards under the 2005 LTIP will remain outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued. On November 28, 2005, the board of directors of our General Partner adopted the 2005 LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2005 LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. The 2005 LTIP phantom units consist of a notional unit based on the value of the Partnership's common units. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be issued and delivered pursuant to awards under the 2005 LTIP. Awards that are canceled or forfeited, or are withheld to satisfy the General Partner’s tax withholding obligations, are available for delivery pursuant to other awards. On February 15, 2012, the board of directors of our General Partner adopted the 2012 LTIP (the "2012 LTIP") for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provided for the grant of phantom units and DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Spectra Energy. The LTIPs were administered by the compensation committee of the General Partner’s board of directors through 2012, and by the General Partner’s board of directors beginning in 2013. All awards under the LTIPs are subject to cliff vesting. Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units on the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date. We recognized less than $1 million , less than $1 million , and $1 million in compensation expense related to our LTIP awards for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, we had less than $1 million of unrecognized compensation expense related to LTIP awards.

Net Income or Loss per Limited

Net Income or Loss per Limited Partner Unit	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income or Loss per Limited Partner Unit	Net Income or Loss per Limited Partner Unit Our net income or loss is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership agreement. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU. Basic and diluted net income or loss per LPU is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under the LTIP. The dilutive effect of unit-based awards was 1,105 , 7,038 and 10,574 equivalent units during the years ended December 31, 2016 , 2015 and 2014 respectively.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flow. Insurance — We have renewed or extended our insurance policies for the 2016-2017 insurance year. We contract with third party insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2) general liability insurance; (3) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (4) property insurance, which covers replacement value of real and personal property and includes business interruption/extra expense; and (5) directors and officers insurance for acts related to our business activities. We are jointly insured with DCP Midstream, LLC for a portion of the insurance placed. These renewals or extensions have not resulted in any material change to the premiums we are contracted to pay. All coverage is subject to certain limits and deductibles, the terms and conditions of which management believes are common for companies that are of similar size to us and with similar types of operations. The insurance on Discovery, as placed by Williams Field Service Group LLC, for the 2016-2017 insurance year includes general and excess liability, onshore property damage, including named windstorm and business interruption, and offshore non-wind property and business interruption insurance. We believe offshore named windstorm property and business interruption insurance that is available comes at uneconomic premium levels, high deductibles and low coverage limits. As such, Discovery continues to elect not to purchase offshore named windstorm property and business interruption insurance coverage for the 2016-2017 insurance year. Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus (i) from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Indemnification — DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and expenses associated with the operation of the assets of certain of our predecessors. Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, totaled $13 million , $11 million , and $13 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term. Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2016 : (Millions) 2017 $ 17 2018 15 2019 14 2020 10 2021 5 Thereafter 13 Total minimum rental payments $ 74

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Business Segments	Business Segments Our operations are located in the United States and were organized into three reporting segments prior to the Transaction: Natural Gas Services; NGL Logistics; and Wholesale Propane Logistics. Our chief operating decision maker regularly reviews financial information about our operating segments, which are aggregated into the reporting units presented, in deciding how to allocate resources and evaluate performance. Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing, treating, processing, transporting and storing natural gas, and fractionating NGLs. The segment consists of our Eagle Ford system, East Texas system, Southeast Texas system, Michigan system, Northern Louisiana system, Southern Oklahoma system, Wyoming system, DJ Basin system, 75% interest in the Piceance system and 40% interest in Discovery. NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of NGLs. The segment consists of our storage facility in Michigan, the DJ Basin fractionators, 12.5% interest in the Mont Belvieu Enterprise fractionator, 20% interest in the Mont Belvieu 1 fractionator, 10% interest in the Texas Express intrastate pipeline, 15% interest in the Panola intrastate pipeline, 33.33% interests in the Southern Hills, Sand Hills and Front Range pipelines, the Black Lake and Wattenberg interstate pipelines and the Seabreeze and Wilbreeze intrastate pipelines. Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of propane and other liquefied petroleum gases by pipeline, rail or ship to our terminals that store and deliver the product to distributors. The segment consists of six rail terminals, one marine terminal, one pipeline terminal and access to several open-access pipeline terminals. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the operations of each segment. The following tables set forth our segment information: Year Ended December 31, 2016 : Natural Gas Services NGL Logistics Wholesale Propane Logistics Other Eliminations (e) Total (Millions) Total operating revenue $ 1,269 $ 85 $ 146 $ — $ (3 ) $ 1,497 Gross margin (a) $ 431 $ 85 $ 35 $ — $ — $ 551 Operating and maintenance expense (153 ) (22 ) (8 ) — — (183 ) Depreciation and amortization expense (111 ) (8 ) (3 ) — — (122 ) General and administrative expense — — — (88 ) — (88 ) Other expense (7 ) — — — — (7 ) Earnings from unconsolidated affiliates 74 140 — — — 214 Interest expense — — — (94 ) — (94 ) Gain on sale of assets 47 — — — — 47 Net income (loss) $ 281 $ 195 $ 24 $ (182 ) $ — $ 318 Net income attributable to noncontrolling interests (6 ) — — — — (6 ) Net income (loss) attributable to partners $ 275 $ 195 $ 24 $ (182 ) $ — $ 312 Non-cash derivative mark-to-market (b) $ (108 ) $ — $ — $ — $ — $ (108 ) Non-cash lower of cost or market adjustments $ 3 $ — $ — $ — $ — $ 3 Capital expenditures $ 27 $ 9 $ 1 $ — $ — $ 37 Investments in unconsolidated affiliates, net $ — $ 29 $ — $ — $ — $ 29 Year Ended December 31, 2015 : Natural Gas NGL Logistics Wholesale Propane Logistics Other Total (Millions) Total operating revenue $ 1,618 $ 80 $ 200 $ — $ 1,898 Gross margin (a) $ 515 $ 80 $ 57 $ — $ 652 Operating and maintenance expense (184 ) (20 ) (10 ) — (214 ) Depreciation and amortization expense (109 ) (8 ) (3 ) — (120 ) General and administrative expense — — — (85 ) (85 ) Goodwill impairment (82 ) — — — (82 ) Other (expense) income (8 ) 4 — — (4 ) Earnings from unconsolidated affiliates 55 118 — — 173 Interest expense — — — (92 ) (92 ) Income tax benefit — — — 5 5 Net income (loss) $ 187 $ 174 $ 44 $ (172 ) $ 233 Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net income (loss) attributable to partners $ 182 $ 174 $ 44 $ (172 ) $ 228 Non-cash derivative mark-to-market (b) $ (133 ) $ — $ 3 $ (1 ) $ (131 ) Non-cash lower of cost or market adjustments $ 6 $ — $ 2 $ — $ 8 Capital expenditures $ 240 $ 37 $ 4 $ — $ 281 Investments in unconsolidated affiliates, net $ 15 $ 47 $ — $ — $ 62 Year Ended December 31, 2014 Natural Gas NGL Wholesale Other Total (Millions) Total operating revenue $ 3,163 $ 73 $ 406 $ — $ 3,642 Gross margin (a) $ 756 $ 73 $ 18 $ — $ 847 Operating and maintenance expense (189 ) (16 ) (11 ) — (216 ) Depreciation and amortization expense (101 ) (7 ) (2 ) — (110 ) General and administrative expense — — — (64 ) (64 ) Other expense (2 ) (1 ) — — (3 ) Earnings from unconsolidated affiliates 5 70 — — 75 Interest expense — — — (86 ) (86 ) Income tax expense — — — (6 ) (6 ) Net income (loss) $ 469 $ 119 $ 5 $ (156 ) $ 437 Net income attributable to noncontrolling interests (14 ) — — — (14 ) Net income (loss) attributable to partners $ 455 $ 119 $ 5 $ (156 ) $ 423 Non-cash derivative mark-to-market (b) $ 89 $ — $ (3 ) $ — $ 86 Non-cash lower of cost or market adjustments $ 11 $ — $ 13 $ — $ 24 Capital expenditures $ 297 $ 25 $ 16 $ — $ 338 Acquisition expenditures $ 102 $ 673 $ — $ — $ 775 Investments in unconsolidated affiliates, net $ 75 $ 76 $ — $ — $ 151 December 31, December 31, 2016 2015 (Millions) Segment long-term assets: Natural Gas Services $ 4,140 $ 4,362 NGL Logistics 672 679 Wholesale Propane Logistics 118 120 Other (d) 4 10 Total long-term assets 4,934 5,171 Current assets 227 306 Total assets $ 5,161 $ 5,477 (a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) The segment information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information, similar to the pooling method. (d) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets. (e) Represents intersegment revenues consisting of sales of NGLs in our NGL Logistics segment to our Wholesale Propane segment.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, 2016 2015 2014 (Millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 84 $ 86 $ 73 Cash paid for income taxes, net of income tax refunds $ 2 $ 2 $ 2 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable $ 11 $ 12 $ 43 Other non-cash changes in property, plant and equipment $ (8 ) $ (8 ) $ 4 Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions $ — $ — $ 65 Non-cash excess purchase price in March 2014 Transactions $ — $ — $ 160

Supplementary Information - Con

Supplementary Information - Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Supplementary Information - Condensed Consolidating Financial Information	Supplementary Information — Condensed Consolidating Financial Information The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 156 — 156 Inventories — — 44 — 44 Other — — 26 — 26 Total current assets — — 227 — 227 Property, plant and equipment, net — — 3,272 — 3,272 Goodwill and intangible assets, net — — 175 — 175 Advances receivable — consolidated subsidiaries 1,676 1,754 — (3,430 ) — Investments in consolidated subsidiaries 925 1,439 — (2,364 ) — Investments in unconsolidated affiliates — — 1,475 — 1,475 Other long-term assets — — 12 — 12 Total assets $ 2,601 $ 3,193 $ 5,161 $ (5,794 ) $ 5,161 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 18 $ 216 $ — $ 234 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 3,430 (3,430 ) — Long-term debt — 1,750 — — 1,750 Other long-term liabilities — — 44 — 44 Total liabilities — 2,268 3,690 (3,430 ) 2,528 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 2,601 928 1,444 (2,364 ) 2,609 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 2,601 925 1,439 (2,364 ) 2,601 Noncontrolling interests — — 32 — 32 Total equity 2,601 925 1,471 (2,364 ) 2,633 Total liabilities and equity $ 2,601 $ 3,193 $ 5,161 $ (5,794 ) $ 5,161 Condensed Consolidating Balance Sheet December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 2 $ — $ 2 Accounts receivable, net — — 154 — 154 Inventories — — 43 — 43 Other — — 107 — 107 Total current assets — — 306 — 306 Property, plant and equipment, net — — 3,476 — 3,476 Goodwill and intangible assets, net — — 184 — 184 Advances receivable — consolidated subsidiaries 2,159 2,023 — (4,182 ) — Investments in consolidated subsidiaries 613 1,033 — (1,646 ) — Investments in unconsolidated affiliates — — 1,493 — 1,493 Other long-term assets — — 18 — 18 Total assets $ 2,772 $ 3,056 $ 5,477 $ (5,828 ) $ 5,477 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 19 $ 181 $ — $ 200 Advances payable — consolidated subsidiaries — — 4,182 (4,182 ) — Long-term debt — 2,424 — — 2,424 Other long-term liabilities — — 48 — 48 Total liabilities — 2,443 4,411 (4,182 ) 2,672 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 2,772 616 1,038 (1,646 ) 2,780 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 2,772 613 1,033 (1,646 ) 2,772 Noncontrolling interests — — 33 — 33 Total equity 2,772 613 1,066 (1,646 ) 2,805 Total liabilities and equity $ 2,772 $ 3,056 $ 5,477 $ (5,828 ) $ 5,477 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1,093 $ — $ 1,093 Transportation, processing and other — — 424 — 424 Losses from commodity derivative activity, net — — (20 ) — (20 ) Total operating revenues — — 1,497 — 1,497 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 946 — 946 Operating and maintenance expense — — 183 — 183 Depreciation and amortization expense — — 122 — 122 General and administrative expense — — 88 — 88 Gain on sale of assets — — (47 ) — (47 ) Other expense — — 7 — 7 Total operating costs and expenses — — 1,299 — 1,299 Operating income — — 198 — 198 Interest expense — (94 ) — — (94 ) Income from consolidated subsidiaries 312 406 — (718 ) — Earnings from unconsolidated affiliates — — 214 — 214 Income before income taxes 312 312 412 (718 ) 318 Income tax expense — — — — — Net income 312 312 412 (718 ) 318 Net income attributable to noncontrolling interests — — (6 ) — (6 ) Net income attributable to partners $ 312 $ 312 $ 406 $ (718 ) $ 312 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 312 $ 312 $ 412 $ (718 ) $ 318 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — — — — — Other comprehensive income from consolidated subsidiaries — — — — — Total other comprehensive income — — — — — Total comprehensive income 312 312 412 (718 ) 318 Total comprehensive income attributable to noncontrolling interests — — (6 ) — (6 ) Total comprehensive income attributable to partners $ 312 $ 312 $ 406 $ (718 ) $ 312 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1,442 $ — $ 1,442 Transportation, processing and other — — 371 — 371 Gains from commodity derivative activity, net — — 85 — 85 Total operating revenues — — 1,898 — 1,898 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 1,246 — 1,246 Operating and maintenance expense — — 214 — 214 Depreciation and amortization expense — — 120 — 120 General and administrative expense — — 85 — 85 Goodwill impairment — — 82 — 82 Other expense — — 4 — 4 Total operating costs and expenses — — 1,751 — 1,751 Operating income — — 147 — 147 Interest expense, net — (92 ) — — (92 ) Income from consolidated subsidiaries 228 320 — (548 ) — Earnings from unconsolidated affiliates — — 173 — 173 Income before income taxes 228 228 320 (548 ) 228 Income tax expense — — 5 — 5 Net income 228 228 325 (548 ) 233 Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net income attributable to partners $ 228 $ 228 $ 320 $ (548 ) $ 228 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 228 $ 228 $ 325 $ (548 ) $ 233 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive income 229 229 325 (549 ) 234 Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive income attributable to partners $ 229 $ 229 $ 320 $ (549 ) $ 229 Condensed Consolidating Statement of Operations Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 3,143 $ — $ 3,143 Transportation, processing and other — — 345 — 345 Gains from commodity derivative activity, net — — 154 — 154 Total operating revenues — — 3,642 — 3,642 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 2,795 — 2,795 Operating and maintenance expense — — 216 — 216 Depreciation and amortization expense — — 110 — 110 General and administrative expense — — 64 — 64 Other expense — — 3 — 3 Total operating costs and expenses — — 3,188 — 3,188 Operating income — — 454 — 454 Interest expense — (86 ) — — (86 ) Earnings from unconsolidated affiliates 423 509 — (932 ) — Income from consolidated subsidiaries — — 75 — 75 Income before income taxes 423 423 529 (932 ) 443 Income tax expense — — (6 ) — (6 ) Net income 423 423 523 (932 ) 437 Net income attributable to noncontrolling interests — — (14 ) — (14 ) Net income attributable to partners $ 423 $ 423 $ 509 $ (932 ) $ 423 (a) The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method. Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 423 $ 423 $ 523 $ (932 ) $ 437 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 2 — — 2 Other comprehensive income from consolidated subsidiaries 2 — — (2 ) — Total other comprehensive income 2 2 — (2 ) 2 Total comprehensive income 425 425 523 (934 ) 439 Total comprehensive income attributable to noncontrolling interests — — (14 ) — (14 ) Total comprehensive income attributable to partners $ 425 $ 425 $ 509 $ (934 ) $ 425 (a) The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method. Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (88 ) $ 663 $ — $ 575 INVESTING ACTIVITIES: Intercompany transfers 483 268 — (751 ) — Capital expenditures — — (37 ) — (37 ) Investments in unconsolidated affiliates — — (29 ) — (29 ) Proceeds from sale of assets — — 160 — 160 Net cash provided by investing activities 483 268 94 (751 ) 94 FINANCING ACTIVITIES: Intercompany transfers — — (751 ) 751 — Proceeds from long-term debt — 1,972 — — 1,972 Payments of long-term debt — (2,152 ) — — (2,152 ) Distributions to limited partners and general partner (483 ) — — — (483 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Net cash used in financing activities (483 ) (180 ) (758 ) 751 (670 ) Net change in cash and cash equivalents — — (1 ) — (1 ) Cash and cash equivalents, beginning of period — — 2 — 2 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (89 ) $ 739 $ — $ 650 INVESTING ACTIVITIES: Intercompany transfers 451 (60 ) — (391 ) — Capital expenditures — — (281 ) — (281 ) Investments in unconsolidated affiliates — — (62 ) — (62 ) Net cash provided by (used in) investing activities 451 (60 ) (343 ) (391 ) (343 ) FINANCING ACTIVITIES: Intercompany transfers — — (391 ) 391 — Proceeds from long-term debt — 1,554 — — 1,554 Payments of long-term debt — (1,429 ) — — (1,429 ) Proceeds from issuance of common units, net of offering costs 31 — — — 31 Distributions to limited partners and general partner (482 ) — — — (482 ) Distributions to noncontrolling interests — — (5 ) — (5 ) Contributions from DCP Midstream, LLC — — 1 — 1 Net cash (used in) provided by financing activities (451 ) 125 (395 ) 391 (330 ) Net change in cash and cash equivalents — (24 ) 1 — (23 ) Cash and cash equivalents, beginning of period — 24 1 — 25 Cash and cash equivalents, end of period $ — $ — $ 2 $ — $ 2 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (73 ) $ 597 $ — $ 524 INVESTING ACTIVITIES: Intercompany transfers (581 ) (280 ) — 861 — Capital expenditures — — (338 ) — (338 ) Acquisitions, net of cash acquired — — (102 ) — (102 ) Investments in unconsolidated affiliates — — (673 ) — (673 ) Acquisition of unconsolidated affiliates — — (151 ) — (151 ) Proceeds from sale of assets — — 28 — 28 Net cash used in investing activities (581 ) (280 ) (1,236 ) 861 (1,236 ) FINANCING ACTIVITIES: Intercompany transfers — — 861 (861 ) — Proceeds from long-term debt — 719 — — 719 Payments of issuance of commercial paper, net — (335 ) — — (335 ) Payment of deferred financing costs — (7 ) — — (7 ) Proceeds from issuance of common units, net of offering costs 1,001 — — — 1,001 Excess purchase price over acquired assets — — (18 ) — (18 ) Net change in advances to predecessor from DCP Midstream, LLC — — (6 ) — (6 ) Distributions to limited partners and general partner (420 ) — — — (420 ) Distributions to noncontrolling interests — — (14 ) — (14 ) Contributions from noncontrolling interests — — 3 — 3 Purchase of additional interest in a subsidiary — — (198 ) — (198 ) Net cash provided by financing activities 581 377 628 (861 ) 725 Net change in cash and cash equivalents — 24 (11 ) — 13 Cash and cash equivalents, beginning of year — — 12 — 12 Cash and cash equivalents, end of year $ — $ 24 $ 1 $ — $ 25 (a) The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On December 30, 2016, we entered into a Contribution Agreement with DCP Midstream, LLC and DCP Midstream Operating, LP. The Transaction closed effective January 1, 2017. For additional information regarding the Transaction, see Note 4 - Acquisitions. Effective January 11, 2017, we changed our name to "DCP Midstream, LP" from "DCP Midstream Partners, LP" (the Name Change). In connection with the Name Change, the ticker symbol for our common units representing limited partner interests listed on the NYSE changed from “DPM” to “DCP” effective at the open of the NYSE on January 23, 2017. On January 26, 2017 , we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on February 14, 2017 to unitholders of record on February 7, 2017 , except that the owners of the Partnership's General Partner will receive distributions on the units issued on January 1, 2017 beginning with the first quarter 2017 declared distribution.

Description of Business and B30

Description of Business and Basis of Presentation Description of Business and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control.
Business Combinations and Other Purchase of Business Transactions, Policy [Policy Text Block]
Equity Method Investments, Policy [Policy Text Block]	Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents.
Allowance for Doubtful Accounts [Policy Text Block]	Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.
Inventory, Policy [Policy Text Block]	Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.
Derivatives, Policy [Policy Text Block]	Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings. The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations. Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through the first quarter of 2018 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. The type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity. Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of operations as a gain or loss on commodity derivative activity. Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016 . Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.
Asset Retirement Obligations and Environmental Cost, Policy [Policy Text Block]	Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill at the reporting unit level during the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows. Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.
Equity and Cost Method Investments, Policy [Policy Text Block]	Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy [Policy Text Block]	Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to: • significant adverse change in legal factors or business climate; • a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset; • significant adverse changes in the extent or manner in which an asset is used, or in its physical condition; • a significant adverse change in the market value of an asset; or • a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition - We generate the majority of our revenues from gathering, compressing, treating, processing, transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by receiving fees. We also generate revenue from transporting, storing and selling propane. We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements: • Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. • Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate. • Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their customers. Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments. We recognize revenues for sales and services under the four revenue recognition criteria, as follows: • Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract. • Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser. • The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody. • Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected. We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. We recognize revenues for non-trading commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity derivative activity . These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial and physical energy trading contracts. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash.
Major Customers, Policy [Policy Text Block]	Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2016 , 2015 and 2014 . However, we had significant transactions with affiliates.
Environmental Costs, Policy [Policy Text Block]	Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. There were no environmental liabilities included in the consolidated balance sheet as other current liabilities at December 31, 2016 and 2015, and other long-term liabilities were $1 million at both December 31, 2016 and 2015 .
Income Tax, Policy [Policy Text Block]	Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal income tax returns of each partner.
Earnings Per Share, Policy [Policy Text Block]	Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

Fair Value Measurement Fair Val

Fair Value Measurement Fair Value Measurement (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Fair Value Measurement, Policy [Policy Text Block]	Determination of Fair Value Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market. • Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided. • Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date. • Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant. We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 13 - Risk Management and Hedging Activities. Valuation Hierarchy Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows. • Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets. • Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3 — inputs are unobservable and considered significant to the fair value measurement. A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy. Commodity Derivative Assets and Liabilities We enter into a variety of derivative financial instruments, which may include over-the-counter, or OTC, instruments, such as natural gas, crude oil or NGL contracts. Within our Natural Gas Services segment, we typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified within Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3. Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs. Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data. Interest Rate Derivative Assets and Liabilities We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation. Nonfinancial Assets and Liabilities We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

Risk Management and Hedging A33

Risk Management and Hedging Activities Derivatives, Methods of Accounting (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Derivatives, Policy [Policy Text Block]	Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings. The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations. Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a portion of our expected commodity price risk associated with our gathering, processing and sales activities through the first quarter of 2018 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange our floating price risk for a fixed price. The type of instrument that we use to mitigate a portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as a gain or a loss on commodity derivative activity. Our Wholesale Propane Logistics segment is generally designed with the intent to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of operations as a gain or loss on commodity derivative activity. Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility. Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase the base gas, the deferred losses or gains would remain in AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016 . Interest Rate Risk We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchase or normal sale exception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows: Classification of Contract Accounting Method Presentation of Gains & Losses or Revenue & Expense Cash Flow Hedge Hedge method (a) Gross basis in the same consolidated statements of operations category as the related hedged item Fair Value Hedge Hedge method (a) Gross basis in the same consolidated statements of operations category as the related hedged item Normal Purchases or Normal Sales Accrual method (b) Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale Other Non-Trading Derivative Activity Mark-to-market method (c) Net basis in gains and losses from commodity derivative activity ______________ (a) Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item. (b) Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings. (c) Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations [Table Text Block]

Agreements and Transactions w36

Agreements and Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of Fees Incurred and Other Fees Paid	The following is a summary of the fees we incurred under the Services Agreement, as well as other fees paid to DCP Midstream, LLC: Year Ended December 31, 2016 2015 2014 (Millions) Services Agreement $ 71 $ 71 $ 41 Other fees — DCP Midstream, LLC 3 3 6 Total — DCP Midstream, LLC $ 74 $ 74 $ 47
Summary of Transactions with Affiliates	The following table summarizes our transactions with affiliates: Year Ended December 31, 2016 2015 2014 (Millions) DCP Midstream, LLC: Sales of natural gas, propane, NGLs and condensate $ 745 $ 958 $ 2,179 Transportation, processing and other $ 167 $ 118 $ 92 Purchases of natural gas, propane and NGLs $ 100 $ 61 $ 194 (Losses) gains from commodity derivative activity, net $ (13 ) $ 33 $ 118 Operating and maintenance expense $ — $ — $ 1 General and administrative expense $ 74 $ 74 $ 47 Phillips 66: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1 Spectra Energy: Purchases of natural gas, propane and NGLs $ 32 $ 46 $ 77 Transportation, processing and other $ — $ — $ 14 Other income $ — $ 5 $ — We had balances with affiliates as follows: December 31, December 31, (Millions) DCP Midstream, LLC: Accounts receivable $ 94 $ 81 Accounts payable $ 28 $ 15 Unrealized gains on derivative instruments — current $ 15 $ 32 Unrealized gains on derivative instruments — long-term $ — $ 9 Unrealized losses on derivative instruments — current $ 22 $ 18 Unrealized losses on derivative instruments — long-term $ — $ 1 Spectra Energy: Accounts payable $ 3 $ 4

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories were as follows: December 31, December 31, (Millions) Natural gas $ 28 $ 29 NGLs 16 14 Total inventories $ 44 $ 43

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Classification of Property, Plant and Equipment	A summary of property, plant and equipment by classification is as follows: Depreciable Life December 31, December 31, (Millions) Gathering and transmission systems 20 — 50 Years $ 2,046 $ 2,337 Processing, storage, and terminal facilities 35 — 60 Years 2,342 2,327 Other 3 — 30 Years 63 64 Construction work in progress 89 122 Property, plant and equipment 4,540 4,850 Accumulated depreciation (1,268 ) (1,374 ) Property, plant and equipment, net $ 3,272 $ 3,476

Investments in Unconsolidated39

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	The following table summarizes our investments in unconsolidated affiliates: Carrying Value as of Percentage Ownership December 31, December 31, (Millions) DCP Sand Hills Pipeline, LLC 33.33% $ 454 $ 441 Discovery Producer Services LLC 40% 386 406 DCP Southern Hills Pipeline, LLC 33.33% 315 318 Front Range Pipeline LLC 33.33% 165 170 Texas Express Pipeline LLC 10% 93 96 Mont Belvieu Enterprise Fractionator 12.5% 23 25 Panola Pipeline Company, LLC 15% 25 19 Mont Belvieu 1 Fractionator 20% 10 11 Other Various 4 7 Total investments in unconsolidated affiliates $ 1,475 $ 1,493
Earnings from Investments in Unconsolidated Affiliates	Earnings from investments in unconsolidated affiliates were as follows: Year Ended December 31, 2016 2015 2014 (Millions) Discovery Producer Services LLC $ 74 $ 55 5 DCP Sand Hills Pipeline, LLC 61 55 24 DCP Southern Hills Pipeline, LLC 24 14 13 Front Range Pipeline LLC 19 17 2 Mont Belvieu Enterprise Fractionator 16 15 16 Mont Belvieu 1 Fractionator 10 9 12 Texas Express Pipeline LLC 8 8 3 Panola Pipeline Company, LLC 2 — — Total earnings from unconsolidated affiliates $ 214 $ 173 $ 75
Equity Method Investment Summarized Financial Information, Statement of Operations	The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Year Ended December 31, 2016 2015 2014 (Millions) Statements of operations (a): Operating revenue $ 1,321 $ 1,172 $ 826 Operating expenses $ 552 $ 540 $ 475 Net income $ 765 $ 630 $ 349
Equity Method Investment Summarized Financial Information, Balance Sheet	December 31, December 31, (Millions) Balance sheets (a): Current assets $ 196 $ 182 Long-term assets 5,272 5,200 Current liabilities (166 ) (170 ) Long-term liabilities (202 ) (216 ) Net assets $ 5,100 $ 4,996 (a) In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016.

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Financial Instruments Carried at Fair Value	The following table presents the financial instruments carried at fair value as of December 31, 2016 and 2015 , by consolidated balance sheet caption and by valuation hierarchy, as described above: December 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Carrying Value Level 1 Level 2 Level 3 Total Carrying Value (Millions) Current assets: Commodity derivatives (a) $ 1 $ 15 $ — $ 16 $ — $ 83 $ 22 $ 105 Short-term investments (b) $ — $ — $ — $ — $ 2 $ — $ — $ 2 Long-term assets: Commodity derivatives (c) $ — $ — $ — $ — $ — $ 9 $ — $ 9 Current liabilities: Commodity derivatives (d) $ (1 ) $ (23 ) $ (5 ) $ (29 ) $ — $ (18 ) $ — $ (18 ) Long-term liabilities: Commodity derivatives (e) $ — $ — $ — $ — $ — $ (1 ) $ — $ (1 ) (a) Included in current unrealized gains on derivative instruments in our consolidated balance sheets. (b) Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets. (c) Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets. (d) Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation	Commodity Derivative Instruments Current Assets Long- Term Assets Current Liabilities Long- Term Liabilities (Millions) Year ended December 31, 2016 (a): Beginning balance $ 22 $ — $ — $ — Net unrealized losses included in earnings (b) — — (5 ) — Settlements (22 ) — — — Ending balance $ — $ — $ (5 ) $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ — $ — $ (5 ) $ — Year ended December 31, 2015 (a): Beginning balance $ 138 $ 18 $ — $ — Net unrealized gains (losses) included in earnings (b) 29 (18 ) — — Settlements (145 ) — — — Ending balance $ 22 $ — $ — $ — Net unrealized gains (losses) on derivatives still held included in earnings (b) $ 21 $ (18 ) $ — $ — (a) There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015 . (b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.
Schedule of Valuation Processes	Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. December 31, 2016 Product Group Fair Value Forward Curve Range (Millions) Liabilities NGLs $ (5 ) $0.66-$1.23 Per gallon
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	As of December 31, 2016 and 2015 , the carrying value and fair value of our long-term fixed-rate Senior Notes, including current maturities, and our Amended and Restated Credit Agreement were as follows: December 31, 2016 December 31, 2015 Carrying Value (a) Fair Value Carrying Value (a) Fair Value (Millions) Senior Notes $ 2,066 $ 2,022 $ 2,063 $ 1,650 Amended and Restated Credit Agreement $ 195 $ 195 $ 375 $ 375

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt	December 31, December 31, (Millions) Amended and Restated Credit Agreement Revolving credit facility, weighted-average variable interest rate of 2.01% and 1.57%, as of December 31, 2016 and 2015 , respe ctively, due May 1, 2019 $ 195 $ 375 Debt Securities Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017 500 500 Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019 325 325 Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022 350 350 Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023 500 500 Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044 400 400 Unamortized issuance costs (11 ) (14 ) Unamortized discount (9 ) (12 ) Total debt 2,250 2,424 Current maturities of long-term debt 500 — Total long-term debt $ 1,750 $ 2,424
Future Maturities of Long-Term Debt	The future maturities of debt in the year indicated are as follows: Debt Maturities (Millions) 2017 $ 500 2018 — 2019 520 2020 — 2021 — Thereafter 1,250 2,270 Unamortized issuance costs (11 ) Unamortized discount (9 ) Total $ 2,250

Risk Management and Hedging A42

Risk Management and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Gross and Net Amounts of Derivative Instruments	The following summarizes the gross and net amounts of our derivative instruments: December 31, 2016 December 31, 2015 Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments (a) Net Amount Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet Amounts Not Offset in the Balance Sheet - Financial Instruments (a) Net Amount (Millions) Assets: Commodity derivatives $ 16 $ (15 ) $ 1 $ 114 $ (19 ) $ 95 Liabilities: Commodity derivatives $ (29 ) $ 15 $ (14 ) $ (19 ) $ 19 $ — (a) There is no cash collateral pledged or received against these positions.
Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value	The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of December 31, 2016 and 2015 . Balance Sheet Line Item December 31, December 31, Balance Sheet Line Item December 31, December 31, (Millions) (Millions) Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging Instruments: Commodity derivatives: Commodity derivatives: Unrealized gains on derivative instruments — current $ 16 $ 105 Unrealized losses on derivative instruments — current $ (29 ) $ (18 ) Unrealized gains on derivative instruments — long-term — 9 Unrealized losses on derivative instruments — long-term — (1 ) Total $ 16 $ 114 Total $ (29 ) $ (19 )
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2016 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2016 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (3 ) $ (6 ) $ 1 $ (8 ) Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. For the year ended December 31, 2016 , no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in gains or losses from commodity derivative activity, net or interest expense in our consolidated statements of operations. For the year ended December 31, 2016 , no derivative losses were reclassified from AOCI to gains or losses from commodity derivative activity, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring. The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015 : Interest Commodity Foreign Total (Millions) Net deferred (losses) gains in AOCI (beginning balance) $ (4 ) $ (6 ) $ 1 $ (9 ) Losses reclassified from AOCI to earnings — effective portion 1 (b) — — 1 Net deferred (losses) gains in AOCI (ending balance) $ (3 ) $ (6 ) $ 1 $ (8 ) (a) Relates to Discovery, an unconsolidated affiliate. (b) Included in interest expense in our consolidated statements of operations.
Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments	The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected: Commodity Derivatives: Statements of Operations Line Item Year Ended December 31, 2016 2015 2014 (Millions) Third party: Realized gains (losses) $ 72 $ 158 $ (2 ) Unrealized (losses) gains (79 ) (106 ) 38 (Losses) gains from commodity derivative activity, net $ (7 ) $ 52 $ 36 Affiliates: Realized gains $ 16 $ 57 $ 70 Unrealized (losses) gains (29 ) (24 ) 48 (Losses) gains from commodity derivative activity, net —affiliates $ (13 ) $ 33 $ 118
Schedule of Net Long or Short Positions Expected to be Realized	The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below. December 31, 2016 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net Short Position (Bbls) Net Long Position (MMBtu) 2017 (212,000 ) (21,192,500 ) (1,605,000 ) 1,567,500 2018 (28,000 ) — — — December 31, 2015 Crude Oil Natural Gas Natural Gas Liquids Natural Gas Basis Swaps Year of Expiration Net Short Position (Bbls) Net Short Position (MMBtu) Net Short Position (Bbls) Net Long Position (MMBtu) 2016 (1,408,672 ) (15,881,064 ) (813,267 ) 2,665,000 2017 — (7,387,500 ) — 1,800,000

Partnership Equity and Distri43

Partnership Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Cash Distribution	The following table presents our cash distributions paid in 2016 , 2015 and 2014: Payment Date Per Unit Distribution Total Cash Distribution (Millions) November 14, 2016 $ 0.7800 $ 120 August 12, 2016 $ 0.7800 $ 121 May 13, 2016 $ 0.7800 $ 121 February 12, 2016 $ 0.7800 $ 121 November 13, 2015 $ 0.7800 $ 120 August 14, 2015 $ 0.7800 $ 121 May 15, 2015 $ 0.7800 $ 121 February 13, 2015 $ 0.7800 $ 120 November 14, 2014 $ 0.7700 $ 117 August 14, 2014 $ 0.7575 $ 111 May 15, 2014 $ 0.7450 $ 106 February 14, 2014 $ 0.7325 $ 86

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	The following tables set forth our segment information: Year Ended December 31, 2016 : Natural Gas Services NGL Logistics Wholesale Propane Logistics Other Eliminations (e) Total (Millions) Total operating revenue $ 1,269 $ 85 $ 146 $ — $ (3 ) $ 1,497 Gross margin (a) $ 431 $ 85 $ 35 $ — $ — $ 551 Operating and maintenance expense (153 ) (22 ) (8 ) — — (183 ) Depreciation and amortization expense (111 ) (8 ) (3 ) — — (122 ) General and administrative expense — — — (88 ) — (88 ) Other expense (7 ) — — — — (7 ) Earnings from unconsolidated affiliates 74 140 — — — 214 Interest expense — — — (94 ) — (94 ) Gain on sale of assets 47 — — — — 47 Net income (loss) $ 281 $ 195 $ 24 $ (182 ) $ — $ 318 Net income attributable to noncontrolling interests (6 ) — — — — (6 ) Net income (loss) attributable to partners $ 275 $ 195 $ 24 $ (182 ) $ — $ 312 Non-cash derivative mark-to-market (b) $ (108 ) $ — $ — $ — $ — $ (108 ) Non-cash lower of cost or market adjustments $ 3 $ — $ — $ — $ — $ 3 Capital expenditures $ 27 $ 9 $ 1 $ — $ — $ 37 Investments in unconsolidated affiliates, net $ — $ 29 $ — $ — $ — $ 29 Year Ended December 31, 2015 : Natural Gas NGL Logistics Wholesale Propane Logistics Other Total (Millions) Total operating revenue $ 1,618 $ 80 $ 200 $ — $ 1,898 Gross margin (a) $ 515 $ 80 $ 57 $ — $ 652 Operating and maintenance expense (184 ) (20 ) (10 ) — (214 ) Depreciation and amortization expense (109 ) (8 ) (3 ) — (120 ) General and administrative expense — — — (85 ) (85 ) Goodwill impairment (82 ) — — — (82 ) Other (expense) income (8 ) 4 — — (4 ) Earnings from unconsolidated affiliates 55 118 — — 173 Interest expense — — — (92 ) (92 ) Income tax benefit — — — 5 5 Net income (loss) $ 187 $ 174 $ 44 $ (172 ) $ 233 Net income attributable to noncontrolling interests (5 ) — — — (5 ) Net income (loss) attributable to partners $ 182 $ 174 $ 44 $ (172 ) $ 228 Non-cash derivative mark-to-market (b) $ (133 ) $ — $ 3 $ (1 ) $ (131 ) Non-cash lower of cost or market adjustments $ 6 $ — $ 2 $ — $ 8 Capital expenditures $ 240 $ 37 $ 4 $ — $ 281 Investments in unconsolidated affiliates, net $ 15 $ 47 $ — $ — $ 62 Year Ended December 31, 2014 Natural Gas NGL Wholesale Other Total (Millions) Total operating revenue $ 3,163 $ 73 $ 406 $ — $ 3,642 Gross margin (a) $ 756 $ 73 $ 18 $ — $ 847 Operating and maintenance expense (189 ) (16 ) (11 ) — (216 ) Depreciation and amortization expense (101 ) (7 ) (2 ) — (110 ) General and administrative expense — — — (64 ) (64 ) Other expense (2 ) (1 ) — — (3 ) Earnings from unconsolidated affiliates 5 70 — — 75 Interest expense — — — (86 ) (86 ) Income tax expense — — — (6 ) (6 ) Net income (loss) $ 469 $ 119 $ 5 $ (156 ) $ 437 Net income attributable to noncontrolling interests (14 ) — — — (14 ) Net income (loss) attributable to partners $ 455 $ 119 $ 5 $ (156 ) $ 423 Non-cash derivative mark-to-market (b) $ 89 $ — $ (3 ) $ — $ 86 Non-cash lower of cost or market adjustments $ 11 $ — $ 13 $ — $ 24 Capital expenditures $ 297 $ 25 $ 16 $ — $ 338 Acquisition expenditures $ 102 $ 673 $ — $ — $ 775 Investments in unconsolidated affiliates, net $ 75 $ 76 $ — $ — $ 151 December 31, December 31, 2016 2015 (Millions) Segment long-term assets: Natural Gas Services $ 4,140 $ 4,362 NGL Logistics 672 679 Wholesale Propane Logistics 118 120 Other (d) 4 10 Total long-term assets 4,934 5,171 Current assets 227 306 Total assets $ 5,161 $ 5,477 (a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. (b) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. (c) The segment information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information, similar to the pooling method. (d) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets. (e) Represents intersegment revenues consisting of sales of NGLs in our NGL Logistics segment to our Wholesale Propane segment.

Supplemental Cash Flow Inform45

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Summary of Supplemental Cash Flow Information	Year Ended December 31, 2016 2015 2014 (Millions) Cash paid for interest: Cash paid for interest, net of amounts capitalized $ 84 $ 86 $ 73 Cash paid for income taxes, net of income tax refunds $ 2 $ 2 $ 2 Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable $ 11 $ 12 $ 43 Other non-cash changes in property, plant and equipment $ (8 ) $ (8 ) $ 4 Non-cash addition of investment in unconsolidated affiliates and property, plant and equipment acquired in March 2014 Transactions $ — $ — $ 65 Non-cash excess purchase price in March 2014 Transactions $ — $ — $ 160

Supplementary Information - C46

Supplementary Information - Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	Condensed Consolidating Balance Sheet December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 1 $ — $ 1 Accounts receivable, net — — 156 — 156 Inventories — — 44 — 44 Other — — 26 — 26 Total current assets — — 227 — 227 Property, plant and equipment, net — — 3,272 — 3,272 Goodwill and intangible assets, net — — 175 — 175 Advances receivable — consolidated subsidiaries 1,676 1,754 — (3,430 ) — Investments in consolidated subsidiaries 925 1,439 — (2,364 ) — Investments in unconsolidated affiliates — — 1,475 — 1,475 Other long-term assets — — 12 — 12 Total assets $ 2,601 $ 3,193 $ 5,161 $ (5,794 ) $ 5,161 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 18 $ 216 $ — $ 234 Current maturities of long-term debt — 500 — — 500 Advances payable — consolidated subsidiaries — — 3,430 (3,430 ) — Long-term debt — 1,750 — — 1,750 Other long-term liabilities — — 44 — 44 Total liabilities — 2,268 3,690 (3,430 ) 2,528 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 2,601 928 1,444 (2,364 ) 2,609 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 2,601 925 1,439 (2,364 ) 2,601 Noncontrolling interests — — 32 — 32 Total equity 2,601 925 1,471 (2,364 ) 2,633 Total liabilities and equity $ 2,601 $ 3,193 $ 5,161 $ (5,794 ) $ 5,161 Condensed Consolidating Balance Sheet December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) ASSETS Current assets: Cash and cash equivalents $ — $ — $ 2 $ — $ 2 Accounts receivable, net — — 154 — 154 Inventories — — 43 — 43 Other — — 107 — 107 Total current assets — — 306 — 306 Property, plant and equipment, net — — 3,476 — 3,476 Goodwill and intangible assets, net — — 184 — 184 Advances receivable — consolidated subsidiaries 2,159 2,023 — (4,182 ) — Investments in consolidated subsidiaries 613 1,033 — (1,646 ) — Investments in unconsolidated affiliates — — 1,493 — 1,493 Other long-term assets — — 18 — 18 Total assets $ 2,772 $ 3,056 $ 5,477 $ (5,828 ) $ 5,477 LIABILITIES AND EQUITY Accounts payable and other current liabilities $ — $ 19 $ 181 $ — $ 200 Advances payable — consolidated subsidiaries — — 4,182 (4,182 ) — Long-term debt — 2,424 — — 2,424 Other long-term liabilities — — 48 — 48 Total liabilities — 2,443 4,411 (4,182 ) 2,672 Commitments and contingent liabilities Equity: Partners’ equity: Net equity 2,772 616 1,038 (1,646 ) 2,780 Accumulated other comprehensive loss — (3 ) (5 ) — (8 ) Total partners’ equity 2,772 613 1,033 (1,646 ) 2,772 Noncontrolling interests — — 33 — 33 Total equity 2,772 613 1,066 (1,646 ) 2,805 Total liabilities and equity $ 2,772 $ 3,056 $ 5,477 $ (5,828 ) $ 5,477
Condensed Income Statement [Table Text Block]	Condensed Consolidating Statement of Operations Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 3,143 $ — $ 3,143 Transportation, processing and other — — 345 — 345 Gains from commodity derivative activity, net — — 154 — 154 Total operating revenues — — 3,642 — 3,642 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 2,795 — 2,795 Operating and maintenance expense — — 216 — 216 Depreciation and amortization expense — — 110 — 110 General and administrative expense — — 64 — 64 Other expense — — 3 — 3 Total operating costs and expenses — — 3,188 — 3,188 Operating income — — 454 — 454 Interest expense — (86 ) — — (86 ) Earnings from unconsolidated affiliates 423 509 — (932 ) — Income from consolidated subsidiaries — — 75 — 75 Income before income taxes 423 423 529 (932 ) 443 Income tax expense — — (6 ) — (6 ) Net income 423 423 523 (932 ) 437 Net income attributable to noncontrolling interests — — (14 ) — (14 ) Net income attributable to partners $ 423 $ 423 $ 509 $ (932 ) $ 423 Condensed Consolidating Statement of Operations Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1,093 $ — $ 1,093 Transportation, processing and other — — 424 — 424 Losses from commodity derivative activity, net — — (20 ) — (20 ) Total operating revenues — — 1,497 — 1,497 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 946 — 946 Operating and maintenance expense — — 183 — 183 Depreciation and amortization expense — — 122 — 122 General and administrative expense — — 88 — 88 Gain on sale of assets — — (47 ) — (47 ) Other expense — — 7 — 7 Total operating costs and expenses — — 1,299 — 1,299 Operating income — — 198 — 198 Interest expense — (94 ) — — (94 ) Income from consolidated subsidiaries 312 406 — (718 ) — Earnings from unconsolidated affiliates — — 214 — 214 Income before income taxes 312 312 412 (718 ) 318 Income tax expense — — — — — Net income 312 312 412 (718 ) 318 Net income attributable to noncontrolling interests — — (6 ) — (6 ) Net income attributable to partners $ 312 $ 312 $ 406 $ (718 ) $ 312 Condensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Operating revenues: Sales of natural gas, propane, NGLs and condensate $ — $ — $ 1,442 $ — $ 1,442 Transportation, processing and other — — 371 — 371 Gains from commodity derivative activity, net — — 85 — 85 Total operating revenues — — 1,898 — 1,898 Operating costs and expenses: Purchases of natural gas, propane and NGLs — — 1,246 — 1,246 Operating and maintenance expense — — 214 — 214 Depreciation and amortization expense — — 120 — 120 General and administrative expense — — 85 — 85 Goodwill impairment — — 82 — 82 Other expense — — 4 — 4 Total operating costs and expenses — — 1,751 — 1,751 Operating income — — 147 — 147 Interest expense, net — (92 ) — — (92 ) Income from consolidated subsidiaries 228 320 — (548 ) — Earnings from unconsolidated affiliates — — 173 — 173 Income before income taxes 228 228 320 (548 ) 228 Income tax expense — — 5 — 5 Net income 228 228 325 (548 ) 233 Net income attributable to noncontrolling interests — — (5 ) — (5 ) Net income attributable to partners $ 228 $ 228 $ 320 $ (548 ) $ 228
Condensed Statement of Comprehensive Income [Table Text Block]	Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 228 $ 228 $ 325 $ (548 ) $ 233 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 1 — — 1 Other comprehensive income from consolidated subsidiaries 1 — — (1 ) — Total other comprehensive income 1 1 — (1 ) 1 Total comprehensive income 229 229 325 (549 ) 234 Total comprehensive income attributable to noncontrolling interests — — (5 ) — (5 ) Total comprehensive income attributable to partners $ 229 $ 229 $ 320 $ (549 ) $ 229 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 423 $ 423 $ 523 $ (932 ) $ 437 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 2 — — 2 Other comprehensive income from consolidated subsidiaries 2 — — (2 ) — Total other comprehensive income 2 2 — (2 ) 2 Total comprehensive income 425 425 523 (934 ) 439 Total comprehensive income attributable to noncontrolling interests — — (14 ) — (14 ) Total comprehensive income attributable to partners $ 425 $ 425 $ 509 $ (934 ) $ 425 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 312 $ 312 $ 412 $ (718 ) $ 318 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — — — — — Other comprehensive income from consolidated subsidiaries — — — — — Total other comprehensive income — — — — — Total comprehensive income 312 312 412 (718 ) 318 Total comprehensive income attributable to noncontrolling interests — — (6 ) — (6 ) Total comprehensive income attributable to partners $ 312 $ 312 $ 406 $ (718 ) $ 312 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) Net income $ 423 $ 423 $ 523 $ (932 ) $ 437 Other comprehensive income: Reclassification of cash flow hedge losses into earnings — 2 — — 2 Other comprehensive income from consolidated subsidiaries 2 — — (2 ) — Total other comprehensive income 2 2 — (2 ) 2 Total comprehensive income 425 425 523 (934 ) 439 Total comprehensive income attributable to noncontrolling interests — — (14 ) — (14 ) Total comprehensive income attributable to partners $ 425 $ 425 $ 509 $ (934 ) $ 425
Condensed Consolidating Statements of Cash Flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (88 ) $ 663 $ — $ 575 INVESTING ACTIVITIES: Intercompany transfers 483 268 — (751 ) — Capital expenditures — — (37 ) — (37 ) Investments in unconsolidated affiliates — — (29 ) — (29 ) Proceeds from sale of assets — — 160 — 160 Net cash provided by investing activities 483 268 94 (751 ) 94 FINANCING ACTIVITIES: Intercompany transfers — — (751 ) 751 — Proceeds from long-term debt — 1,972 — — 1,972 Payments of long-term debt — (2,152 ) — — (2,152 ) Distributions to limited partners and general partner (483 ) — — — (483 ) Distributions to noncontrolling interests — — (7 ) — (7 ) Net cash used in financing activities (483 ) (180 ) (758 ) 751 (670 ) Net change in cash and cash equivalents — — (1 ) — (1 ) Cash and cash equivalents, beginning of period — — 2 — 2 Cash and cash equivalents, end of period $ — $ — $ 1 $ — $ 1 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (89 ) $ 739 $ — $ 650 INVESTING ACTIVITIES: Intercompany transfers 451 (60 ) — (391 ) — Capital expenditures — — (281 ) — (281 ) Investments in unconsolidated affiliates — — (62 ) — (62 ) Net cash provided by (used in) investing activities 451 (60 ) (343 ) (391 ) (343 ) FINANCING ACTIVITIES: Intercompany transfers — — (391 ) 391 — Proceeds from long-term debt — 1,554 — — 1,554 Payments of long-term debt — (1,429 ) — — (1,429 ) Proceeds from issuance of common units, net of offering costs 31 — — — 31 Distributions to limited partners and general partner (482 ) — — — (482 ) Distributions to noncontrolling interests — — (5 ) — (5 ) Contributions from DCP Midstream, LLC — — 1 — 1 Net cash (used in) provided by financing activities (451 ) 125 (395 ) 391 (330 ) Net change in cash and cash equivalents — (24 ) 1 — (23 ) Cash and cash equivalents, beginning of period — 24 1 — 25 Cash and cash equivalents, end of period $ — $ — $ 2 $ — $ 2 Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2014 (a) Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Consolidating Adjustments Consolidated (Millions) OPERATING ACTIVITIES Net cash (used in) provided by operating activities $ — $ (73 ) $ 597 $ — $ 524 INVESTING ACTIVITIES: Intercompany transfers (581 ) (280 ) — 861 — Capital expenditures — — (338 ) — (338 ) Acquisitions, net of cash acquired — — (102 ) — (102 ) Investments in unconsolidated affiliates — — (673 ) — (673 ) Acquisition of unconsolidated affiliates — — (151 ) — (151 ) Proceeds from sale of assets — — 28 — 28 Net cash used in investing activities (581 ) (280 ) (1,236 ) 861 (1,236 ) FINANCING ACTIVITIES: Intercompany transfers — — 861 (861 ) — Proceeds from long-term debt — 719 — — 719 Payments of issuance of commercial paper, net — (335 ) — — (335 ) Payment of deferred financing costs — (7 ) — — (7 ) Proceeds from issuance of common units, net of offering costs 1,001 — — — 1,001 Excess purchase price over acquired assets — — (18 ) — (18 ) Net change in advances to predecessor from DCP Midstream, LLC — — (6 ) — (6 ) Distributions to limited partners and general partner (420 ) — — — (420 ) Distributions to noncontrolling interests — — (14 ) — (14 ) Contributions from noncontrolling interests — — 3 — 3 Purchase of additional interest in a subsidiary — — (198 ) — (198 ) Net cash provided by financing activities 581 377 628 (861 ) 725 Net change in cash and cash equivalents — 24 (11 ) — 13 Cash and cash equivalents, beginning of year — — 12 — 12 Cash and cash equivalents, end of year $ — $ 24 $ 1 $ — $ 25 (a) The financial information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant, a transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information similar to the pooling method.

Description of Business and B47

Description of Business and Basis of Presentation - Additional Information (Detail)	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Ownership interest percentage by parent		100.00%
Investments in Greater Than 20% [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Investments in Less Than 20% [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Phillips 66 [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent		50.00%
Spectra Energy [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent		50.00%
DCP Midstream, LLC [Member]
Business Acquisition [Line Items]
Ownership interest percentage by parent	21.40%

Summary of Significant Accoun48

Summary of Significant Accounting Policies (Details) $ in Millions	Dec. 31, 2016USD ($)
Summary Of Significant Accounting Policies [Line Items]
Accrued Environmental Loss Contingencies, Noncurrent	$ 1

New Accounting Pronouncements49

New Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
debt issuance cost [Abstract]
Unamortized Debt Issuance Expense	$ 11	$ 14

Acquisitions - Additional Infor

Acquisitions - Additional Information (Detail) - DCP Midstream, LLC [Member] - Subsequent Event [Member] $ in Millions	Jan. 01, 2017USD ($)shares
Business Acquisition [Line Items]
Cash acquired	$ 424
Debt assumed	3,150
Payment for incentive fee	$ 100
Common Units [Member]
Business Acquisition [Line Items]
Equity interest issued, number of units | shares	28,552,480
General Partner Units [Member]
Business Acquisition [Line Items]
Equity interest issued, number of units | shares	2,550,644

Assets Held for Sale (Details)

Assets Held for Sale (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents		$ 160
Disposal Group, Including Discontinued Operation, Liabilities, Current		500
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ (47)	$ (47)	$ 0	$ 0

Agreements and Transactions w52

Agreements and Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC		$ 3	$ 3	$ 6
Transportation, processing and other		424	371	345
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC		3		2
Eagle Ford System [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC				4
Affiliated Entity [Member] | DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Transportation, processing and other		$ 167	118	$ 92
Maximum [Member] | DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Other fees - DCP Midstream, LLC	$ 1		$ 3

Agreements and Transactions w53

Agreements and Transactions with Affiliates - Schedule of Fees Incurred and Other Fees Paid (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Services/Omnibus Agreement		$ 71	$ 71	$ 41
Other fees - DCP Midstream, LLC		3	3	6
Total - DCP Midstream, LLC		88	85	64
Related Party Transaction, Amounts of Transaction		71
Transportation, processing and other		424	371	345
DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC		3		2
DCP Midstream, LLC [Member] | Affiliated Entity [Member]
Total - DCP Midstream, LLC		74	74	47
Transportation, processing and other		$ 167	118	92
Eagle Ford System [Member]
Other fees - DCP Midstream, LLC				$ 4
Maximum [Member] | DCP Midstream, LLC [Member]
Other fees - DCP Midstream, LLC	$ 1		$ 3

Agreements and Transactions w54

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	$ 1,093	$ 1,442	$ 3,143
Transportation, processing and other	424	371	345
Other Operating Income (Expense), Net	7	4	3
Purchases of natural gas, propane and NGLs	946	1,246	2,795
Gain (Loss) on Derivative Instruments, Net, Pretax	(20)	85	154
Operating and maintenance expense	183	214	216
General and administrative expense	88	85	64
Affiliated Entity [Member] | DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	745	958	2,179
Transportation, processing and other	167	118	92
Purchases of natural gas, propane and NGLs	100	61	194
Operating and maintenance expense	0	0	1
General and administrative expense	74	74	47
Affiliated Entity [Member] | DCP Midstream, LLC [Member] | Commodity Derivatives [Member]
Related Party Transaction [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(13)	33	118
Affiliated Entity [Member] | Phillips 66 [Member]
Related Party Transaction [Line Items]
Sales of natural gas, propane, NGLs and condensate	0	0	1
Affiliated Entity [Member] | Spectra Energy [Member]
Related Party Transaction [Line Items]
Transportation, processing and other	0	0	14
Other Operating Income (Expense), Net	0	5	0
Purchases of natural gas, propane and NGLs	$ 32	$ 46	$ 77

Agreements and Transactions w55

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable	$ 94	$ 81
Accounts payable	31	19
DCP Midstream, LLC [Member]
Related Party Transaction [Line Items]
Accounts receivable	94	81
Accounts payable	28	15
Unrealized gains on derivative instruments - current	15	32
Unrealized gains on derivative instruments - long-term	0	9
Unrealized losses on derivative instruments - current	22	18
Unrealized losses on derivative instruments - long-term	0	1
Spectra Energy [Member]
Related Party Transaction [Line Items]
Accounts payable	$ 3	$ 4

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Components Of Inventory [Line Items]
Total inventories	$ 44	$ 43
Natural Gas [Member]
Components Of Inventory [Line Items]
Total inventories	28	29
Natural Gas Liquids [Member]
Components Of Inventory [Line Items]
Total inventories	$ 16	$ 14

Inventories - Additional Inform

Inventories - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory Write-down	$ 3	$ 8	$ 24

Property, Plant and Equipment -

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 4,850	$ 4,540	$ 4,850
Accumulated depreciation	(1,374)	(1,268)	(1,374)
Property, plant and equipment, net	3,476	3,272	3,476
Interest Costs Capitalized	0	1	6	$ 8
Depreciation		112	110	$ 101
Disposal Group, Including Discontinued Operation, Depreciation and Amortization	2
Gathering and Transmission Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,337	$ 2,046	2,337
Gathering and Transmission Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		20 years
Gathering and Transmission Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		50 years
Processing, Storage, and Terminal Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,327	$ 2,342	2,327
Processing, Storage, and Terminal Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		35 years
Processing, Storage, and Terminal Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		60 years
Other Energy Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	64	$ 63	64
Other Energy Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		3 years
Other Energy Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment		30 years
Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 122	$ 89	$ 122

Property, Plant and Equipment59

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Interest Costs Capitalized	$ 0	$ 1	$ 6	$ 8
Depreciation		112	110	$ 101
Asset Retirement Obligation, Accretion Expense		2
Disposal Group, Including Discontinued Operation, Depreciation and Amortization	2
Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligations, Noncurrent	$ 29	$ 28	$ 29

Goodwill and Intangible asset60

Goodwill and Intangible assets Schedule of Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Goodwill			$ 72	$ 72	$ 154
Goodwill, Impairment Loss			0	(82)	0
Natural Gas Services [Member]
Goodwill [Line Items]
Goodwill			0	0	82
Goodwill, Impairment Loss	$ (33)	$ (49)	0	(82)
NGL Logistics [Member]
Goodwill [Line Items]
Goodwill			35	35	35
Goodwill, Impairment Loss			0	0
Wholesale Propane Logistics [Member]
Goodwill [Line Items]
Goodwill			37	37	$ 37
Goodwill, Impairment Loss			$ 0	$ 0

Goodwill and Intangible asset61

Goodwill and Intangible assets Schedule of Finite-Lived Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Finite-Lived Intangible Assets, Gross			$ 164
Finite-Lived Intangible Assets, Accumulated Amortization	$ (61)	$ (52)
Intangible assets, net	103	112	164
Amortization of Intangible Assets	$ 9	$ 8	$ 9

Goodwill and Intangible asset62

Goodwill and Intangible assets Finite-Lived Intangible Assets, Future Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	$ 8
Finite-Lived Intangible Assets, Amortization Expense, Year Three	8
Finite-Lived Intangible Assets, Amortization Expense, Year Four	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	8
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	63
Intangible assets, net	$ 103	$ 112	$ 164
Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	5 years
Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	19 years
Weighted Average [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	14 years

Investments In Unconsolidated63

Investments In Unconsolidated Affiliates - Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 1,475	$ 1,493
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 454	441
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	40.00%
Investments in unconsolidated affiliates	$ 386	406
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	$ 315	318
Front Range Pipeline LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
Investments in unconsolidated affiliates	$ 165	170
Texas Express Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	10.00%
Investments in unconsolidated affiliates	$ 93	96
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	12.50%
Investments in unconsolidated affiliates	$ 23	25
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Investments in unconsolidated affiliates	$ 10	11
Panola [Member]
Investments in and Advances to Affiliates [Line Items]
Equity Method Investment, Ownership Percentage	15.00%
Investments in unconsolidated affiliates	$ 25	19
Other [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage description	Various
Investments in unconsolidated affiliates	$ 4	$ 7

Investments in Unconsolidated64

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 214	$ 173	$ 75
Sand Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	61	55	24
Mont Belvieu 1 Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	10	9	12
Southern Hills Pipeline [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	24	14	13
Mont Belvieu Enterprise Fractionator [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	16	15	16
Discovery Producer Services LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	74	55	5
Texas Express [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	8	8	3
Front Range [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	19	17	2
Panola [Member]
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 2	$ 0	$ 0

Investments in Unconsolidated65

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 1,321	$ 1,172	$ 826
Operating expenses	552	540	475
Net income	$ 765	$ 630	$ 349

Investments in Unconsolidated66

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 196	$ 182
Long-term assets	5,272	5,200
Current liabilities	(166)	(170)
Long-term liabilities	(202)	(216)
Net assets	$ 5,100	$ 4,996

Fair Value Measurement - Financ

Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments		$ 0	$ 2
Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[1]	16	105
Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[2]	0	9
Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[3]	(29)	(18)
Commodity Derivative [Member] | Long-Term Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[4]	0	(1)
Level 1 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments		0	2
Level 1 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[1]	1	0
Level 1 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[2]	0	0
Level 1 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[3]	(1)	0
Level 1 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[4]	0	0
Level 2 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments		0	0
Level 2 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[1]	15	83
Level 2 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[2]	0	9
Level 2 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[3]	(23)	(18)
Level 2 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[4]	0	(1)
Fair Value, Inputs, Level 3 [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term investments		0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Derivative [Member] | Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[1]	0	22
Fair Value, Inputs, Level 3 [Member] | Commodity Derivative [Member] | Long-Term Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[2]	0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Derivative [Member] | Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[3]	(5)	0
Fair Value, Inputs, Level 3 [Member] | Commodity Derivative [Member] | Long-Term Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	[4]	$ 0	$ 0
[1]	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.
[2]	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.
[3]	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
[4]	.

Fair Value Measurement - Conden

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Current Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	[1]	$ 22	$ 138
Net realized and unrealized gains (losses) included in earnings	[1],[2]	0	29
Settlements	[1]	(22)	(145)
Ending balance	[1]	0	22
Net unrealized gains still held included in earnings	[1],[2]	0	21
Long-Term Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	[1]	0	18
Net realized and unrealized gains (losses) included in earnings	[1],[2]	0	(18)
Settlements	[1]	0	0
Ending balance	[1]	0	0
Net unrealized gains still held included in earnings	[1],[2]	0	(18)
Current Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	[1]	0	0
Net realized and unrealized (losses) gains included in earnings	[1],[2]	(5)	0
Settlements	[1]	0	0
Ending balance	[1]	(5)	0
Net unrealized gains (losses) still held included in earnings	[1],[2]	(5)	0
Long-Term Liabilities [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	[1]	0	0
Net realized and unrealized (losses) gains included in earnings	[1],[2]	0	0
Settlements	[1]	0	0
Ending balance	[1]	0	0
Net unrealized gains (losses) still held included in earnings	[1],[2]	$ 0	$ 0
[1]	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015.
[2]	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

Fair Value Measurement - Schedu

Fair Value Measurement - Schedule of Valuation Processes (Detail)	Dec. 31, 2016$ / MMBTU$ / gal$ / Gallon
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range | $ / gal	0.66
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Derivative Financial Instruments, Assets [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range | $ / Gallon	1.23
Senior Notes, 3.25% Due 2015 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.25%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	2.50%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	5.60%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	4.95%
Senior Notes, 3.875% Due 2023 [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Senior notes interest rate percentage	3.875%
Derivative Financial Instruments, Liabilities [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0
Derivative Financial Instruments, Liabilities [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Market Approach Valuation Technique [Member] | Natural Gas Liquids [Member]
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0

Fair Value Measurement - Additi

Fair Value Measurement - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Goodwill, Impairment Loss			$ 0	$ 82	$ 0
Debt Instrument, Carrying Amount			2,066	2,063
Debt Instrument, Fair Value			$ 2,022	1,650
Senior Notes, 3.875% Due 2023 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			3.875%
Senior Notes, 2.50% Due 2017 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			2.50%
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			2.70%
Senior Notes, 4.95% Due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			4.95%
Senior Notes, 3.25% Due 2015 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			3.25%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes interest rate percentage			5.60%
Credit Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying value of outstanding balances			$ 195	375
Fair value of outstanding balances			195	375
Natural Gas Services [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Goodwill, Impairment Loss	$ 33	$ 49	0	$ 82
Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member] | Market Approach Valuation Technique [Member] | Maximum [Member] | Natural Gas Liquids [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial and Nonfinancial Liabilities, Fair Value Disclosure			$ 5

Debt - Schedule of Long-Term De

Debt - Schedule of Long-Term Debt (Detail) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Long-term Debt, Current Maturities		$ 500	$ 0
Unamortized Debt Issuance Expense		(11)	(14)
Unamortized discount		(9)	(12)
Total		2,250	2,424
Total long-term debt		1,750	2,424
Senior Notes, 3.875% Due 2023 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount		500	500
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount		400	400
Senior Notes, 2.50% Due 2017 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount		500	500
Senior Notes, 4.95% Due 2022 [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount		350	350
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Line of Credit Facility [Line Items]
Debt Securities Issued Amount		325	325
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average variable interest rate of 2.01% and 1.57%, as of December 31, 2016 and 2015, respectively, due May 1, 2019	[1]	$ 195	$ 375
[1]	December 31, 2016 December 31, 2015 (Millions)Amended and Restated Credit Agreement Revolving credit facility, weighted-average variable interest rate of 2.01% and 1.57%, as of December 31, 2016 and 2015, respectively, due May 1, 2019$195 $375Debt Securities Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017500 500Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019325 325Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022350 350Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023500 500Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044400 400Unamortized issuance costs(11) (14)Unamortized discount(9) (12)Total debt2,250 2,424Current maturities of long-term debt500 —Total long-term debt$1,750 $2,424

Debt - Schedule of Long-Term 72

Debt - Schedule of Long-Term Debt (Parenthetical) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maturity date		May 1, 2019
Fair value of outstanding balances	[1]	$ 195	$ 375
Senior Notes, 3.875% Due 2023 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage		3.875%
Maturity date		Mar. 15, 2023
Senior Notes, 2.50% Due 2017 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage		2.50%
Maturity date		Dec. 1, 2017
Senior Notes, 4.95% Due 2022 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage		4.95%
Maturity date		Apr. 1, 2022
Senior Notes, 3.25% Due 2015 [Member]
Line of Credit Facility [Line Items]
Senior notes interest rate percentage		3.25%
Maturity date		Oct. 1, 2015
[1]	December 31, 2016 December 31, 2015 (Millions)Amended and Restated Credit Agreement Revolving credit facility, weighted-average variable interest rate of 2.01% and 1.57%, as of December 31, 2016 and 2015, respectively, due May 1, 2019$195 $375Debt Securities Issued November 27, 2012, interest at 2.50% payable semi-annually, due December 1, 2017500 500Issued March 13, 2014, interest at 2.70% payable semi-annually, due April 1, 2019325 325Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022350 350Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15, 2023500 500Issued March 13, 2014, interest at 5.60% payable semi-annually, due April 1, 2044400 400Unamortized issuance costs(11) (14)Unamortized discount(9) (12)Total debt2,250 2,424Current maturities of long-term debt500 —Total long-term debt$1,750 $2,424

Debt - Additional Information (

Debt - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Proceeds from long-term debt	$ 1,972	$ 1,554	$ 719
Senior Notes Two Point Seven Zero Percent Due Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 325	325
Senior notes interest rate percentage	2.70%
Senior Notes Five Point Six Zero Percent Due Two Thousand Forty Four [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 400	400
Senior notes interest rate percentage	5.60%
Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 500	500
Senior notes interest rate percentage	3.875%
Maturity date	Mar. 15, 2023
Senior Notes, 2.50% Due 2017 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 500	500
Senior notes interest rate percentage	2.50%
Maturity date	Dec. 1, 2017
Senior Notes, 4.95% Due 2022 [Member]
Debt Instrument [Line Items]
Senior notes issued	$ 350	$ 350
Senior notes interest rate percentage	4.95%
Maturity date	Apr. 1, 2022
Senior Notes, 3.25% Due 2015 [Member]
Debt Instrument [Line Items]
Senior notes interest rate percentage	3.25%
Maturity date	Oct. 1, 2015
Eagle Ford System [Member] | Senior Notes, 3.875% Due 2023 [Member]
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		46.67%
Amended and Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,000
Credit Agreement [Member]
Debt Instrument [Line Items]
Line of credit facility, maturity date	May 1, 2019
Unused capacity under the credit agreement	$ 1,031
Basis spread determined by credit rating	0.45%
Commitment fee percentage	0.30%
London Interbank Offered Rate (LIBOR) [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.45%
Federal Funds Effective Swap Rate [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
London Interbank Offered Rate (LIBOR) Market Index [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of credit issued		1
Letters of Credit Outstanding, Amount	$ 24	$ 1
Minimum [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	1
Temporary maximum leverage ratio post-acquisition	1
Maximum [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum leverage ratio	5
Temporary maximum leverage ratio post-acquisition	5.5
Pro Forma [Member] | Credit Agreement [Member]
Debt Instrument [Line Items]
Unused capacity under the credit agreement	$ 970

Debt - Future Maturities of Lon

Debt - Future Maturities of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Maturities of Long-term Debt [Abstract]
2,014	$ 500
2,015	0
2,016	520
2,017	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Thereafter	1,250
Total principal	2,270
Unamortized Debt Issuance Expense	11	$ 14
Unamortized discount	(9)	$ (12)
Total	$ 2,250

Risk Management and Hedging A75

Risk Management and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Accumulated other comprehensive loss	$ (8)	$ (8)
Collateral Already Posted, Aggregate Fair Value	$ 9
Common unitholders, units issued	114,749,848	114,740,148
Commodity Derivatives [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ (1)
Cash Flow Hedge [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	(8)	$ (8)	$ (9)
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	(6)	(6)	(6)
Cash Flow Hedge [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	$ (3)	(3)	$ (4)
Senior Notes, 4.95% Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Credit Agreement [Member]
Derivative [Line Items]
Letters of Credit Outstanding, Amount	$ 24	$ 1

Risk Management and Hedging A76

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity Derivatives [Member] - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Fair Values Of Financial Assets And Liabilities Including Derivative Financial Instruments [Line Items]
Gross Amounts of Assets Presented in the Balance Sheet		$ 16	$ 114
Amounts Not Offset in the Balance Sheet - Financial Instruments	[1]	(15)	(19)
Net Amount, Assets		1	95
Gross Amounts of Liabilities Presented in the Balance Sheet		(29)	(19)
Amounts Not Offset in the Balance Sheet - Financial Instruments	[1]	15	19
Net Amount, Liabilities		$ 14	$ 0
[1]	There is no cash collateral pledged or received against these positions.

Risk Management and Hedging A77

Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	$ 16	$ 105
Unrealized gains on derivative instruments - long-term	0	9
Derivative Liability [Abstract]
Unrealized losses on derivative instruments - long-term	0	(1)
Commodity Derivatives [Member] | Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	16	105
Unrealized gains on derivative instruments - long-term	0	9
Derivative assets, fair value, total	16	114
Commodity Derivatives [Member] | Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	29	18
Unrealized losses on derivative instruments - long-term	0	(1)
Derivative liabilities, fair value, total	$ (29)	$ (19)

Risk Management and Hedging A78

Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred losses in AOCI (ending balance)	$ (8)
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(9)
Gains (losses) recognized in AOCI on derivatives - effective portion	1
Net deferred losses in AOCI (ending balance)	(8)
Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(4)
Gains (losses) recognized in AOCI on derivatives - effective portion	1	[1]
Net deferred losses in AOCI (ending balance)	(3)
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(6)
Gains (losses) recognized in AOCI on derivatives - effective portion	0
Net deferred losses in AOCI (ending balance)	(6)
Cash Flow Hedge [Member] | Foreign Currency Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	1
Gains (losses) recognized in AOCI on derivatives - effective portion	0	[2]
Net deferred losses in AOCI (ending balance)	$ 1	[2]
[1]	.
[2]	Relates to Discovery, an unconsolidated affiliate.

Risk Management and Hedging A79

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Commodity Derivatives [Member]
Derivative [Line Items]
Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing	$ 1

Risk Management and Hedging A80

Risk Management and Hedging Activities - Schedule of Derivatives Accounted for as Cash Flow Hedges (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Derivative [Line Items]
Accumulated other comprehensive loss		$ (8)		$ (8)
Commodity Derivatives [Member]
Derivative [Line Items]
Losses Recognized in Income on Derivatives - Ineffective Portion and Amount Excluded From Effectiveness Testing		(1)
Cash Flow Hedge [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		(8)		(8)		$ (9)
Losses Reclassified From AOCI to Earnings-Effective Portion				1
Cash Flow Hedge [Member] | Interest Rate Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		(3)		(3)		(4)
Losses Reclassified From AOCI to Earnings-Effective Portion	[1]			1
Cash Flow Hedge [Member] | Commodity Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		(6)		(6)		(6)
Losses Reclassified From AOCI to Earnings-Effective Portion				0
Cash Flow Hedge [Member] | Foreign Currency Derivatives [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		$ 1	[2]	1	[2]	$ 1
Losses Reclassified From AOCI to Earnings-Effective Portion	[2]			$ 0
[1]	.
[2]	Relates to Discovery, an unconsolidated affiliate.

Risk Management and Hedging A81

Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - Derivative Assets Not Designated As Hedging Instruments [Member] - Commodity Derivatives [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Affiliates [Member]
Derivative [Line Items]
Realized	$ 16	$ 57	$ 70
Unrealized	(29)	(24)	48
(Losses) gains from commodity derivative activity, net	(13)	33	118
Third Party [Member]
Derivative [Line Items]
Realized	72	158	(2)
Unrealized	(79)	(106)	38
(Losses) gains from commodity derivative activity, net	$ (7)	$ 52	$ 36

Risk Management and Hedging A82

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	12 Months Ended
	Dec. 31, 2016MMBTUbbl	Dec. 31, 2015MMBTUbbl
Crude Oil [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2014 | bbl	(212,000)	(1,408,672)
Net (Short) Position (Bbls), 2015 | bbl	(28,000)	0
Natural Gas [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2014 | MMBTU	(21,192,500)	(15,881,064)
Net Long (Short) Position (MMBtu), 2015 | MMBTU	0	(7,387,500)
Natural Gas Liquids [Member]
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), 2014 | bbl	(1,605,000)	(813,267)
Net (Short) Position (Bbls), 2015 | bbl	0	0
Natural Gas Basis Swaps [Member]
Derivative [Line Items]
Net Long (Short) Position (MMBtu), 2014 | MMBTU	1,567,500	2,665,000
Net Long (Short) Position (MMBtu), 2015 | MMBTU	0	1,800,000

Partnership Equity and Distri83

Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued	114,749,848	114,740,148
Issuance of common units		790,280
Partnership deadline for distributions (in days)	45 days
General Partner [Member]
Partnership Equity And Distribution [Line Items]
General partner ownership interest	0.00%
Limited Partner [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued			14,375,000
Issuance of common units	0
Price per common unit			$ 48.90
Net proceeds			$ 677
Consideration financed through issuance of common units			4,497,158
Limited partner ownership interest	2.00%
Distribution Stage First [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4025
Distribution Stage Second [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4375
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	13.00%
Distribution Stage Third [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.525
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	23.00%
Distribution Stage Thereafter [Member]
Partnership Equity And Distribution [Line Items]
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	48.00%
Sand Hills Pipeline [Member]
Partnership Equity And Distribution [Line Items]
Equity Method Investment, Ownership Percentage	33.33%
2014 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued	788,033		2,256,066
Proceeds from issuance of common stock	$ 31		$ 119
Offering costs	1		1
Maximum aggregate offering amount			$ 500
Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Offer value of common stock remaining available for sale	$ 349

Partnership Equity and Distri84

Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partnership Equity And Distribution [Line Items]
Total Cash Distribution (Millions)	$ 483	$ 482	$ 420
November fourteenth Two Thousand Sixteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 120
May thirteenth Two Thousand Sixteen [Member] [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
August twelfth Two Thousand Sixteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
February twelfth Two Thousand Sixteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
November thirteen Two Thousand Fifteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 120
august fourteen Two Thousand Fifteen [Member] [Member] [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
May Fifteen Two Thousand Fifteen [Member] [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 121
February Thirteen Two Thousand Fifteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.78
Total Cash Distribution (Millions)	$ 120
November Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.77
Total Cash Distribution (Millions)	$ 117
August Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7575
Total Cash Distribution (Millions)	$ 111
May Fifteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.745
Total Cash Distribution (Millions)	$ 106
February Fourteen Two Thousand Fourteen [Member]
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7325
Total Cash Distribution (Millions)	$ 86
Distribution Stage First [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4025
Distribution Stage Second [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4375
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	13.00%
Distribution Stage Third [Member]
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.525
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	23.00%
Distribution Stage Thereafter [Member]
Partnership Equity And Distribution [Line Items]
Incentive Distribution Payments Made And Minimum Distribution Level Percentage	48.00%

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
State Gross Margin Tax Rate	0.75%	0.75%	0.95%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	850,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	$ 1
Allocated Share-based Compensation Expense	$ 1	$ 1	$ 1

Net Income or Loss per Limite86

Net Income or Loss per Limited Partner Unit - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Weighted Average Number Diluted Limited Partnership Units Outstanding Adjustment	1,105	7,038	10,574

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
State Gross Margin Tax Rate	0.75%	0.75%	0.95%
Current State and Local Tax Expense (Benefit)	$ 2	$ 0	$ 3
Deferred State and Local Income Tax Expense (Benefit)	(2)	(5)	3
Income tax expense	0	(5)	$ 6
Deferred Tax Liabilities, Net, Noncurrent	$ 6	$ 8

Commitments and Contingent Li88

Commitments and Contingent Liabilities Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense, Net	$ 13	$ 11	$ 13
Operating Leases, Future Minimum Payments Due, Next Twelve Months	17
Operating Leases, Future Minimum Payments, Due in Two Years	15
Operating Leases, Future Minimum Payments, Due in Three Years	14
Operating Leases, Future Minimum Payments, Due in Four Years	10
Operating Leases, Future Minimum Payments, Due in Five Years	5
Operating Leases, Future Minimum Payments, Due Thereafter	13
Operating Leases, Future Minimum Payments Due	$ 74

Business Segments - Additional

Business Segments - Additional Information (Detail) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)SegmentProject	Dec. 31, 2015USD ($)Project		Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Total operating revenues	$ 398	$ 372	$ 348	$ 379	$ 435	$ 465	$ 430	$ 568	$ 1,497	$ 1,898		$ 3,642
Number of reporting segments | Segment									3
Ownership interest percentage					100.00%					100.00%
Number of owned and operated rail terminals | Project									6
Number of owned marine import terminals | Project									1
Number of leased marine terminals | Project									1
Pipeline Terminals | Project										1
Gross margin									$ 551	$ 652	[1]	847	[1]
Other Cost and Expense, Operating									(183)	(214)		(216)
Depreciation, Depletion and Amortization, Nonproduction									(122)	(120)		(110)
General and Administrative Expense									(88)	(85)		(64)
Earnings from unconsolidated affiliates									214	173		75
Interest Expense									(94)	(92)		(86)
Income tax expense									0	5		(6)
Net income	80	120	46	72	$ 94	72	(2)	69	318	233		437
Net income attributable to noncontrolling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)		(14)
Net income attributable to partners	$ 75	$ 120	$ 45	$ 72	$ 90	$ 71	$ (2)	$ 69	312	228		423
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									(108)	(131)		86
Capital expenditures									37	281		338
Acquisition expenditures												775
Investments in unconsolidated affiliates, net									$ 29	62		151
Sand Hills Pipeline [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	33.33%								33.33%
Natural Gas Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues									$ 1,269	1,618		3,163
Gross margin									431	515		756
Other Cost and Expense, Operating									(153)	(184)		(189)
Depreciation, Depletion and Amortization, Nonproduction									(111)	(109)		(101)
General and Administrative Expense									0	0		0
Earnings from unconsolidated affiliates									74	55		5
Interest Expense									0	0		0
Income tax expense										0		0
Net income									281	187		469
Net income attributable to noncontrolling interests									(6)	(5)		(14)
Net income attributable to partners									275	182		455
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									(108)	(133)		89
Capital expenditures									27	240		297
Acquisition expenditures												102
Investments in unconsolidated affiliates, net									$ 0	15		75
Colorado [Member]
Segment Reporting Information [Line Items]
Ownership interest percentage	75.00%								75.00%
Discovery Producer Services LLC [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	40.00%								40.00%
Mont Belvieu 1 Fractionator [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	20.00%								20.00%
Mont Belvieu Enterprise Fractionator [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	12.50%								12.50%
Southern Hills Pipeline [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	33.33%								33.33%
Texas Express [Member]
Segment Reporting Information [Line Items]
Ownership interest percentage in subsidiary									10.00%
Panola [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	15.00%								15.00%
NGL Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues									$ 85	80		73
Gross margin									85	80		73
Other Cost and Expense, Operating									(22)	(20)		(16)
Depreciation, Depletion and Amortization, Nonproduction									(8)	(8)		(7)
General and Administrative Expense									0	0		0
Earnings from unconsolidated affiliates									140	118		70
Interest Expense									0	0		0
Income tax expense										0		0
Net income									195	174		119
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									195	174		119
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	0		0
Capital expenditures									9	37		25
Acquisition expenditures												673
Investments in unconsolidated affiliates, net									29	47		76
Wholesale Propane Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues									146	200		406
Gross margin									35	57		18
Other Cost and Expense, Operating									(8)	(10)		(11)
Depreciation, Depletion and Amortization, Nonproduction									(3)	(3)		(2)
General and Administrative Expense									0	0		0
Earnings from unconsolidated affiliates									0	0		0
Interest Expense									0	0		0
Income tax expense										0		0
Net income									24	44		5
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									24	44		5
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	3		(3)
Capital expenditures									1	4		16
Acquisition expenditures												0
Investments in unconsolidated affiliates, net									0	0		0
Other [Member]
Segment Reporting Information [Line Items]
Total operating revenues									0	0		0
Gross margin									0	0	[1]	0	[1]
Other Cost and Expense, Operating									0	0		0
Depreciation, Depletion and Amortization, Nonproduction									0	0		0
General and Administrative Expense									(88)	(85)		(64)
Earnings from unconsolidated affiliates									0	0		0
Interest Expense									(94)	(92)		(86)
Income tax expense										5		(6)
Net income									(182)	(172)		(156)
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									(182)	(172)		(156)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	(1)		0
Capital expenditures									0	0		0
Acquisition expenditures												0
Investments in unconsolidated affiliates, net									$ 0	$ 0		$ 0
Front Range Pipeline [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	33.33%								33.33%
[1]	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

Business Segments - Segment Inf

Business Segments - Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Segment Reporting Information [Line Items]
Total operating revenues	$ 398	$ 372	$ 348	$ 379	$ 435	$ 465	$ 430	$ 568	$ 1,497	$ 1,898		$ 3,642
Gross margin									551	652	[1]	847	[1]
Operating and maintenance expense									(183)	(214)		(216)
Depreciation and amortization expense									(122)	(120)		(110)
General and administrative expense									(88)	(85)		(64)
Other Operating Income (Expense), Net									(7)	(4)		(3)
Goodwill, Impairment Loss									0	(82)		0
Earnings from unconsolidated affiliates									214	173		75
Interest Expense									(94)	(92)		(86)
Income Tax Expense (Benefit)									0	5		(6)
Net income	80	120	46	72	94	72	(2)	69	318	233		437
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		47							47	0		0
Net income attributable to noncontrolling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)		(14)
Net income attributable to partners	75	$ 120	$ 45	$ 72	90	71	(2)	$ 69	312	228		423
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									(108)	(131)		86
Non-cash lower of cost or market adjustments									3	8		24
Capital expenditures									37	281		338
Acquisition expenditures												775
Investments in unconsolidated affiliates, net									29	62		151
Total long-term assets	4,934				5,171				4,934	5,171
Current assets	227				306				227	306
Total assets	5,161				5,477				5,161	5,477
Natural Gas Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues									1,269	1,618		3,163
Gross margin									431	515		756
Operating and maintenance expense									(153)	(184)		(189)
Depreciation and amortization expense									(111)	(109)		(101)
General and administrative expense									0	0		0
Other Operating Income (Expense), Net									(7)	(8)		(2)
Goodwill, Impairment Loss						$ (33)	$ (49)		0	(82)
Earnings from unconsolidated affiliates									74	55		5
Interest Expense									0	0		0
Income Tax Expense (Benefit)										0		0
Net income									281	187		469
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									47
Net income attributable to noncontrolling interests									(6)	(5)		(14)
Net income attributable to partners									275	182		455
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									(108)	(133)		89
Non-cash lower of cost or market adjustments									3	6		11
Capital expenditures									27	240		297
Acquisition expenditures												102
Investments in unconsolidated affiliates, net									0	15		75
Total long-term assets	4,140				4,362				4,140	4,362
NGL Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues									85	80		73
Gross margin									85	80		73
Operating and maintenance expense									(22)	(20)		(16)
Depreciation and amortization expense									(8)	(8)		(7)
General and administrative expense									0	0		0
Other Operating Income (Expense), Net									0	4		(1)
Goodwill, Impairment Loss									0	0
Earnings from unconsolidated affiliates									140	118		70
Interest Expense									0	0		0
Income Tax Expense (Benefit)										0		0
Net income									195	174		119
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									195	174		119
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	0		0
Non-cash lower of cost or market adjustments									0	0		0
Capital expenditures									9	37		25
Acquisition expenditures												673
Investments in unconsolidated affiliates, net									29	47		76
Total long-term assets	672				679				672	679
Wholesale Propane Logistics [Member]
Segment Reporting Information [Line Items]
Total operating revenues									146	200		406
Gross margin									35	57		18
Operating and maintenance expense									(8)	(10)		(11)
Depreciation and amortization expense									(3)	(3)		(2)
General and administrative expense									0	0		0
Other Operating Income (Expense), Net									0	0		0
Goodwill, Impairment Loss									0	0
Earnings from unconsolidated affiliates									0	0		0
Interest Expense									0	0		0
Income Tax Expense (Benefit)										0		0
Net income									24	44		5
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									24	44		5
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	3		(3)
Non-cash lower of cost or market adjustments									0	2		13
Capital expenditures									1	4		16
Acquisition expenditures												0
Investments in unconsolidated affiliates, net									0	0		0
Total long-term assets	118				120				118	120
Other [Member]
Segment Reporting Information [Line Items]
Total operating revenues									0	0		0
Gross margin									0	0	[1]	0	[1]
Operating and maintenance expense									0	0		0
Depreciation and amortization expense									0	0		0
General and administrative expense									(88)	(85)		(64)
Other Operating Income (Expense), Net									0	0		0
Goodwill, Impairment Loss										0
Earnings from unconsolidated affiliates									0	0		0
Interest Expense									(94)	(92)		(86)
Income Tax Expense (Benefit)										5		(6)
Net income									(182)	(172)		(156)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Net income attributable to noncontrolling interests									0	0		0
Net income attributable to partners									(182)	(172)		(156)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0	(1)		0
Non-cash lower of cost or market adjustments									0	0		0
Capital expenditures									0	0		0
Acquisition expenditures												0
Investments in unconsolidated affiliates, net									0	0		$ 0
Total long-term assets	$ 4				$ 10				4	$ 10
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total operating revenues									(3)
Operating and maintenance expense									0
Depreciation and amortization expense									0
General and administrative expense									0
Other Operating Income (Expense), Net									0
Earnings from unconsolidated affiliates									0
Interest Expense									0
Net income									0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Net income attributable to noncontrolling interests									0
Net income attributable to partners									0
Unrealized Gain (Loss) on Derivatives and Commodity Contracts									0
Non-cash lower of cost or market adjustments									0
Capital expenditures									0
Investments in unconsolidated affiliates, net									$ 0
[1]	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

Business Segments - Segment I91

Business Segments - Segment Information (Parenthetical) (Detail) - Project	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Number of owned and operated rail terminals	6
Number of owned marine import terminals	1
Marine Terminals	1
Pipeline Terminals		1

Supplemental Cash Flow Inform92

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$ 84	$ 86	$ 73
Cash paid for income taxes, net of income tax refunds	2	2	2
Property, plant and equipment acquired with accounts payable	11	12	43
Other non-cash additions of property, plant and equipment	(8)	(8)	(4)
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	0	0	65
Non-cash excess purchase price in March 2014 Transactions	$ 0	$ 0	$ 160

Quarterly Financial Data (Detai

Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 398	$ 372	$ 348	$ 379	$ 435	$ 465	$ 430	$ 568	$ 1,497	$ 1,898	$ 3,642
Operating Income (Loss)	47	86	18	47	63	43	(28)	69	198	147	454
Net income	80	120	46	72	94	72	(2)	69	318	233	437
Net income attributable to noncontrolling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)	(14)
Net income attributable to partners	75	120	45	72	90	71	(2)	69	312	228	423
Net Income (Loss) Allocated to Limited Partners	$ 44	$ 89	$ 14	$ 41	$ 59	$ 40	$ (33)	$ 38	$ 188	$ 104	$ 303
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax	$ 0.38	$ 0.78	$ 0.12	$ 0.36	$ 0.51	$ 0.35	$ (0.29)	$ 0.33	$ 1.64	$ 0.91	$ 2.84

Supplementary Information - C94

Supplementary Information - Condensed Consolidating Financial Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016
Parent Guarantor [Member]
Parent Company Only Financial Information [Line Items]
Ownership interest percentage in subsidiary	100.00%

Supplementary Information - C95

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 1	$ 2	$ 25	$ 12	$ 12
Accounts receivable, net	156	154
Inventories	44	43
Other	26	107
Total current assets	227	306
Property, plant and equipment, net	3,272	3,476
Goodwill and intangible assets, net	175	184
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,475	1,493
Other long-term assets	12	18
Total assets	5,161	5,477
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	234	200
Disposal Group, Including Discontinued Operation, Liabilities, Current	500
Advances payable - consolidated subsidiaries	0	0
Long-term debt	1,750	2,424
Other long-term liabilities	44	48
Total liabilities	2,528	2,672
Commitments and contingent liabilities
Equity:
Net equity	2,609	2,780
Accumulated other comprehensive loss	(8)	(8)
Total partners' equity	2,601	2,772
Noncontrolling interests	32	33
Total equity	2,633	2,805	3,026	2,213
Total liabilities and equity	5,161	5,477
Parent Guarantor [Member]
ASSETS
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	1,676	2,159
Investments in consolidated subsidiaries	925	613
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	2,601	2,772
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Disposal Group, Including Discontinued Operation, Liabilities, Current	0
Advances payable - consolidated subsidiaries	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	0	0
Commitments and contingent liabilities
Equity:
Net equity	2,601	2,772
Accumulated other comprehensive loss	0	0
Total partners' equity	2,601	2,772
Noncontrolling interests	0	0
Total equity	2,601	2,772
Total liabilities and equity	2,601	2,772
Subsidiary Issuer [Member]
ASSETS
Cash and cash equivalents	0	0	24	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	1,754	2,023
Investments in consolidated subsidiaries	1,439	1,033
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	3,193	3,056
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	18	19
Disposal Group, Including Discontinued Operation, Liabilities, Current	500
Advances payable - consolidated subsidiaries	0	0
Long-term debt	1,750	2,424
Other long-term liabilities	0	0
Total liabilities	2,268	2,443
Commitments and contingent liabilities
Equity:
Net equity	928	616
Accumulated other comprehensive loss	(3)	(3)
Total partners' equity	925	613
Noncontrolling interests	0	0
Total equity	925	613
Total liabilities and equity	3,193	3,056
Non-Guarantor Subsidiaries [Member]
ASSETS
Cash and cash equivalents	1	2	1	12
Accounts receivable, net	156	154
Inventories	44	43
Other	26	107
Total current assets	227	306
Property, plant and equipment, net	3,272	3,476
Goodwill and intangible assets, net	175	184
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	1,475	1,493
Other long-term assets	12	18
Total assets	5,161	5,477
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	216	181
Disposal Group, Including Discontinued Operation, Liabilities, Current	0
Advances payable - consolidated subsidiaries	3,430	4,182
Long-term debt	0	0
Other long-term liabilities	44	48
Total liabilities	3,690	4,411
Commitments and contingent liabilities
Equity:
Net equity	1,444	1,038
Accumulated other comprehensive loss	(5)	(5)
Total partners' equity	1,439	1,033
Noncontrolling interests	32	33
Total equity	1,471	1,066
Total liabilities and equity	5,161	5,477
Consolidation, Eliminations [Member]
ASSETS
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	(3,430)	(4,182)
Investments in consolidated subsidiaries	(2,364)	(1,646)
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	(5,794)	(5,828)
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Disposal Group, Including Discontinued Operation, Liabilities, Current	0
Advances payable - consolidated subsidiaries	(3,430)	(4,182)
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	(3,430)	(4,182)
Commitments and contingent liabilities
Equity:
Net equity	(2,364)	(1,646)
Accumulated other comprehensive loss	0	0
Total partners' equity	(2,364)	(1,646)
Noncontrolling interests	0	0
Total equity	(2,364)	(1,646)
Total liabilities and equity	$ (5,794)	$ (5,828)

Supplementary Information - C96

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									$ 1,093	$ 1,442	$ 3,143
Transportation, processing and other									424	371	345
Gain (Loss) on Derivative Instruments, Net, Pretax									(20)	85	154
Total operating revenues	$ 398	$ 372	$ 348	$ 379	$ 435	$ 465	$ 430	$ 568	1,497	1,898	3,642
Purchases of natural gas, propane and NGLs									946	1,246	2,795
Operating and maintenance expense									183	214	216
Depreciation and amortization expense									122	120	110
General and administrative expense									88	85	64
Goodwill, Impairment Loss									0	82	0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		(47)							(47)	0	0
Other Operating Income (Expense), Net									7	4	3
Total operating costs and expenses									1,299	1,751	3,188
Operating Income (Loss)	47	86	18	47	63	43	(28)	69	198	147	454
Interest Expense									(94)	(92)	(86)
Income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									214	173	75
Income before income taxes									318	228	443
Income tax expense									0	5	(6)
Net income	80	120	46	72	94	72	(2)	69	318	233	437
Net income attributable to noncontrolling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)	(14)
Net income attributable to partners	$ 75	$ 120	$ 45	$ 72	$ 90	$ 71	$ (2)	$ 69	312	228	423
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Goodwill, Impairment Loss										0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Other Operating Income (Expense), Net									0	0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest Expense									0	0	0
Income from consolidated subsidiaries									312	228	423
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									312	228	423
Income tax expense									0	0	0
Net income									312	228	423
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									312	228	423
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Goodwill, Impairment Loss										0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Other Operating Income (Expense), Net									0	0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest Expense									(94)	(92)	(86)
Income from consolidated subsidiaries									406	320	509
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									312	228	423
Income tax expense									0	0	0
Net income									312	228	423
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									312	228	423
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									1,093	1,442	3,143
Transportation, processing and other									424	371	345
Gain (Loss) on Derivative Instruments, Net, Pretax									(20)	85	154
Total operating revenues									1,497	1,898	3,642
Purchases of natural gas, propane and NGLs									946	1,246	2,795
Operating and maintenance expense									183	214	216
Depreciation and amortization expense									122	120	110
General and administrative expense									88	85	64
Goodwill, Impairment Loss										82
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									(47)
Other Operating Income (Expense), Net									7	4	3
Total operating costs and expenses									1,299	1,751	3,188
Operating Income (Loss)									198	147	454
Interest Expense									0	0	0
Income from consolidated subsidiaries									0	0	0
Earnings from unconsolidated affiliates									214	173	75
Income before income taxes									412	320	529
Income tax expense									0	5	(6)
Net income									412	325	523
Net income attributable to noncontrolling interests									(6)	(5)	(14)
Net income attributable to partners									406	320	509
Consolidation, Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, propane, NGLs and condensate									0	0	0
Transportation, processing and other									0	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas, propane and NGLs									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Goodwill, Impairment Loss										0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0
Other Operating Income (Expense), Net									0	0	0
Total operating costs and expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest Expense									0	0	0
Income from consolidated subsidiaries									(718)	(548)	(932)
Earnings from unconsolidated affiliates									0	0	0
Income before income taxes									(718)	(548)	(932)
Income tax expense									0	0	0
Net income									(718)	(548)	(932)
Net income attributable to noncontrolling interests									0	0	0
Net income attributable to partners									$ (718)	$ (548)	$ (932)

Supplementary Information - C97

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Net income attributable to partners	$ 75	$ 120	$ 45	$ 72	$ 90	$ 71	$ (2)	$ 69	$ 312	$ 228	$ 423
Net income	$ 80	$ 120	$ 46	$ 72	$ 94	$ 72	$ (2)	$ 69	318	233	437
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	1	2
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									0	1	2
Total comprehensive income									318	234	439
Total comprehensive income (loss) attributable to noncontrolling interests									(6)	(5)	(14)
Total comprehensive income attributable to partners									312	229	425
Parent Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Net income attributable to partners									312	228	423
Net income									312	228	423
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									0	1	2
Total other comprehensive income									0	1	2
Total comprehensive income									312	229	425
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									312	229	425
Subsidiary Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Net income attributable to partners									312	228	423
Net income									312	228	423
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	1	2
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									0	1	2
Total comprehensive income									312	229	425
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									312	229	425
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net income attributable to partners									406	320	509
Net income									412	325	523
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									0	0	0
Total comprehensive income									412	325	523
Total comprehensive income (loss) attributable to noncontrolling interests									(6)	(5)	(14)
Total comprehensive income attributable to partners									406	320	509
Consolidation, Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net income attributable to partners									(718)	(548)	(932)
Net income									(718)	(548)	(932)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									0	(1)	(2)
Total other comprehensive income									0	(1)	(2)
Total comprehensive income									(718)	(549)	(934)
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income attributable to partners									$ (718)	$ (549)	$ (934)

Supplementary Information - C98

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$ 575	$ 650	$ 524
Payments for (Proceeds from) Other Investing Activities	0	0	0
INVESTING ACTIVITIES:
Capital expenditures	(37)	(281)	(338)
Acquisitions, net of cash acquired	0	0	(102)
Investments in unconsolidated affiliates, net	(29)	(62)	(151)
Proceeds from sale of assets	160	0	28
Net cash provided by (used in) investing activities	94	(343)	(1,236)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,972	1,554	719
Repayments of Long-term Debt	(2,152)	(1,429)	0
Payments of commercial paper, net	0	0	(335)
Payments of deferred financing costs	0	0	(7)
Excess purchase price over acquired net assets and commodity hedge	0	0	(18)
Proceeds from issuance of common units, net of offering cost	0	31	1,001
Excess Purchase Price Over Acquired Assets			(178)
Net change in advances to predecessor from DCP Midstream, LLC	0	0	(6)
Payments of Ordinary Dividends	(483)	(482)	(420)
Distributions to noncontrolling interests	(7)	(5)	(14)
Payments to Noncontrolling Interests	0	0	(198)
Contributions from noncontrolling interests	0	0	3
Payments of Capital Distribution	(483)	(482)	(420)
Payments Of Distributions To Parent			(198)
Contributions from DCP Midstream, LLC	0	1	0
Net cash (used in) provided by financing activities	(670)	(330)	725
Net change in cash and cash equivalents	(1)	(23)	13
Cash and cash equivalents, beginning of period	2	25	12
Cash and cash equivalents, end of period	1	2	25
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			(102)
Payments to Acquire Equity Method Investments	0	0	673
Parent Guarantor [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0	0
Payments for (Proceeds from) Other Investing Activities	483	451	(581)
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Investments in unconsolidated affiliates, net	0	0	0
Proceeds from sale of assets	0		0
Net cash provided by (used in) investing activities	483	451	(581)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Repayments of Long-term Debt	0	0
Payments of commercial paper, net			0
Payments of deferred financing costs			0
Excess purchase price over acquired net assets and commodity hedge			0
Proceeds from issuance of common units, net of offering cost		31	1,001
Net change in advances to predecessor from DCP Midstream, LLC			0
Payments of Ordinary Dividends	(483)	(482)	(420)
Distributions to noncontrolling interests	0	0	0
Contributions from noncontrolling interests			0
Payments of Capital Distribution			0
Contributions from DCP Midstream, LLC		0
Net cash (used in) provided by financing activities	(483)	(451)	581
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Payments to Acquire Equity Method Investments			0
Subsidiary Issuer [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	(88)	(89)	(73)
Payments for (Proceeds from) Other Investing Activities	268	(60)	(280)
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Investments in unconsolidated affiliates, net	0	0	0
Proceeds from sale of assets	0		0
Net cash provided by (used in) investing activities	268	(60)	(280)
Proceeds from (Payments for) Other Financing Activities	0	0	0
FINANCING ACTIVITIES:
Proceeds from long-term debt	1,972	1,554	719
Repayments of Long-term Debt	(2,152)	(1,429)
Payments of commercial paper, net			(335)
Payments of deferred financing costs			(7)
Excess purchase price over acquired net assets and commodity hedge			0
Proceeds from issuance of common units, net of offering cost		0	0
Net change in advances to predecessor from DCP Midstream, LLC			0
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from noncontrolling interests			0
Payments of Capital Distribution			0
Contributions from DCP Midstream, LLC		0
Net cash (used in) provided by financing activities	(180)	125	377
Net change in cash and cash equivalents	0	(24)	24
Cash and cash equivalents, beginning of period	0	24	0
Cash and cash equivalents, end of period	0	0	24
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Payments to Acquire Equity Method Investments			0
Non-Guarantor Subsidiaries [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	663	739	597
Payments for (Proceeds from) Other Investing Activities	0	0	0
INVESTING ACTIVITIES:
Capital expenditures	(37)	(281)	(338)
Investments in unconsolidated affiliates, net	(29)	(62)	(151)
Proceeds from sale of assets	160		28
Net cash provided by (used in) investing activities	94	(343)	(1,236)
Proceeds from (Payments for) Other Financing Activities	(751)	(391)	861
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Repayments of Long-term Debt	0	0
Payments of commercial paper, net			0
Payments of deferred financing costs			0
Excess purchase price over acquired net assets and commodity hedge			(18)
Proceeds from issuance of common units, net of offering cost		0	0
Net change in advances to predecessor from DCP Midstream, LLC			(6)
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	(7)	(5)	(14)
Contributions from noncontrolling interests			3
Payments of Capital Distribution			(198)
Contributions from DCP Midstream, LLC		1
Net cash (used in) provided by financing activities	(758)	(395)	628
Net change in cash and cash equivalents	(1)	1	(11)
Cash and cash equivalents, beginning of period	2	1	12
Cash and cash equivalents, end of period	1	2	1
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			(102)
Payments to Acquire Equity Method Investments			673
Consolidation, Eliminations [Member]
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0	0
Payments for (Proceeds from) Other Investing Activities	(751)	(391)	861
INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Investments in unconsolidated affiliates, net	0	0	0
Proceeds from sale of assets	0		0
Net cash provided by (used in) investing activities	(751)	(391)	861
Proceeds from (Payments for) Other Financing Activities	751	391	(861)
FINANCING ACTIVITIES:
Proceeds from long-term debt	0	0	0
Repayments of Long-term Debt	0	0
Payments of commercial paper, net			0
Payments of deferred financing costs			0
Excess purchase price over acquired net assets and commodity hedge			0
Proceeds from issuance of common units, net of offering cost		0	0
Net change in advances to predecessor from DCP Midstream, LLC			0
Payments of Ordinary Dividends	0	0	0
Distributions to noncontrolling interests	0	0	0
Contributions from noncontrolling interests			0
Payments of Capital Distribution			0
Contributions from DCP Midstream, LLC		0
Net cash (used in) provided by financing activities	751	391	(861)
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	0
Payments to Acquire Businesses and Interest in Affiliates, Net of Cash Acquired			0
Payments to Acquire Equity Method Investments			$ 0

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 14, 2017	Feb. 07, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Common unitholders, units issued			114,749,848	114,740,148
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution of dividend	$ 0.78
Distribution payable date	Feb. 14, 2017
Distribution record date		Feb. 7, 2017
Equity Distribution Agreement [Member]
Subsequent Event [Line Items]
Offer value of common stock remaining available for sale			$ 349